# TECHNICAL SUPPORT DOCUMENT

Revisions to Texas New Source Review State Im plementation Plan Related to the Standard
Permit for Installation and/or Modification of Oil and Gas Facilities and Standard Permit Applicability

30 TAC Chapter 116, Subchapter F, Section 6 10, Paragraphs a and b, Section 617, Paragraph 3, and Section 620 (30 TAC 116.610(a) and (b), 116.617(3), and 116.620)

Revisions submitted on September 20, 1995; April 19, 1996; July 22, 1998; September 11, 2000; February 1, 2006; and March 11, 2011

December 3, 2013

FOR FURTHER INFORMATION CONTACT: Ms. As hley Mohr, United States Environmental Protection Agency Region 6, Air Permits Section (6PD-R), 1445 Ross Avenue, Suite 1200, Dallas, Texas, 75202-2733, (214) 665-7289

# Technical Support Document
Revisions to Texas New Source Review State Im plementation Plan Related to the Standard

Permit for Installation and/or Modification of Oil and Gas Facilities and to the Standard Permit Applicability Provisions 30 TAC Chapter 116, Subchapter F, Section 6 10, Paragraphs a and b, Section 617, Paragraph 3, and Section 620 (30 TAC 116.610(a) and (b), 116.617(3), and 116.620)

1 Discussion of Revisions to 30 TAC 116.610( a) and (b), 116.617(3), and 116.620 – Standard
Permit for Installation and/or Modification of Oil and Gas Facilities (Oil and Gas Standard Permit) and Standard Permit Applicability Provisions

I. Introduction.

A. Overview. This Technical Support Document (T SD) is a technical evaluation of submitted revisions to the Texas Minor New Source Review (NSR) State Implementation Plan (SIP) that relate to the Oil and Gas Standard Permit and the Standard Permit applicability provisions. Specifically, this is an evaluation of SIP
revisions to the Title 30 of the Texa s Administrative Code (30 TAC), Chapter 116, Section 610, Paragraphs a and b, S ection 617, Paragraph 3, and Section 620.

B. What are we addressing in this action? EPA is addressing portions of the SIP
revisions identified below that relate to the Oil and Gas Standard Permit provisions and the Standard Permit applicability provisions. Additional information regarding the revisions addresse d in this action is included in Tables 1 and 2 in Section II, and in Appendix B.

 Submitted September 20, 1995: Standard Permits. Establishes Standard
Permit for Oil and Gas Facilities at 30 TAC 116, Section 617, Paragraph 3.

 Submitted April 19, 1996: MSW Standard Permits. Moves Standard Permit for Oil and Gas Facilities to newly established 30 TAC Chapter 116, Section
620 and revises the Standard Permit.

 Submitted July 22, 1998: NSR Rule Revisions; §112(g). Revises Standard Permit for Oil and Gas Facilities in Section 620. (Rule Log Number 98001- 116-AI)

 Submitted September 11, 2000: Air Permits (SB 766). Revises Standard
Permit for Oil and Gas Facilities in Section 620. (Rule Log Number 1999- 29B-116-AI)

 Submitted February 1, 2006: Chapter 116 NSR Rule Revisions. Revised Paragraphs a and b of the Standard Permit applicability provisions in Section 610. (Rule Log Number 2005-01 0-1 16-PR)

 Submitted March 11, 2011: Chapter 116 NSR Rule Revisions. Resubmittal of the changes to the Standard Permit applicability provisi ons in Section 610 adopted in 2006. (Rule Log Number 2010-008-116-PR)

# Technical Support Document
Revisions to Texas New Source Review State Im plementation Plan Related to the Standard

Permit for Installation and/or Modification of Oil and Gas Facilities and to the Standard Permit Applicability Provisions 30 TAC Chapter 116, Subchapter F, Section 6 10, Paragraphs a and b, Section 617, Paragraph 3, and Section 620 (30 TAC 116.610(a) and (b), 116.617(3), and 116.620)

2 C. What are we not addressing in this action? As part of this action, EPA is reviewing only those portions of the aforementioned submittals that are applicable to the Oil and Gas Standard Permit and the Standard Permit applicability provisions. The SIP submittals addressed in this action also include additional unrelated, severable, revi sions to 30 TAC Chapters 101 and 116, which are not addressed as part of this action.

II. Overview of the Submitted Revisions to Chapter 116, Section 610, Paragraphs a and b, Section 617, Paragraph 3, and Section 620.

A. Are any of the rules and regulations whic h are evaluated in this action currently SIP-approved? The rules and regulations which re late to the Oil and Gas Standard Permit are not currently SIP-approved. The Standard Permit applicability provisions contained in S ection 610(a) and (b) are currently SIP-approved.

B. What are we reviewing in this action? The pending SIP revi sions are summarized in Tables 1 and 2 below. See the Appe ndix for further details on the specific changes that were submitted.

Table 1. Summary of Pending SIP Submi ttals Addressed in this Action

Title of SIP submittal Date
submitted

to EPA Date of
State adoption Affected Regulations Related to Oil and Gas Standard
Permit

Standard Permits 09/20/1995 07/26/1995 Addition of New Paragraph 30 TAC 116.617(3) –
Installation and/or Modification of Oil and Gas Facilities

 Established a Standard Permit for Oil and Gas

Facilities

MSW Standard Permits 04/19/1996 03/26/1996 Deletion of 30 TAC 116.617(3) – Installation and/or
Modification of Oil and Gas Facilities
Addition of New Section 30 TAC 116.620 – Installation
and/or Modification of Oil and Gas Facilities.

 Deletion of 30 TAC 116.617(3) – Installation and/or

Modification of Oil and Gas Facilities

 The Oil and Gas Standard Permit was moved and

renumbered from 116.617(3) to 116.620 and
sections renumbered to conform these sections to Texas Register style conventions

NSR Rule Revisions;

§112(g) 07/22/1998 06/17/1998 Revision to 30 TAC 116.620 – Installation and/or
Modification of Oil and Gas Facilities

Air Permits (SB 766) 09/11/2000 04/07/2000 Revision to 30 TAC 116.620 – Installation and/or
Modification of Oil and Gas Facilities

# Technical Support Document
Revisions to Texas New Source Review State Im plementation Plan Related to the Standard

Permit for Installation and/or Modification of Oil and Gas Facilities and to the Standard Permit Applicability Provisions 30 TAC Chapter 116, Subchapter F, Section 6 10, Paragraphs a and b, Section 617, Paragraph 3, and Section 620 (30 TAC 116.610(a) and (b), 116.617(3), and 116.620)

3 Title of SIP submittal Date
submitted

to EPA Date of
State adoption Affected Regulations Related to Oil and Gas Standard
Permit

Chapter 116 NSR Rule

Revisions 02/01/2006 01/11/2006 Revision to 30 TAC 116.610 – Standard Permits Applicability

Chapter 116 NSR Rule

Revisions 03/11/2011 01/11/2006 Resubmittal of January 11, 2006 revisions to 30 TAC
116.610



# Table 2. Summary of the Individual Re visions to Each Section Evaluated

Section Title Date
submitted

to EPA Adopted by State Comments

Chapter 116 – Control of Air Pollution by Permits New Construction or Modification

Subchapter F – Standard Permits

Section

116.610 Applicability 02/01/06 01/11/06  Non-substantive revisions to §116.620(a) and (b)

03/11/11 01/11/06  Resubmittal of 2006 adopted changes to §116.620(a) and (b)

Section

116.617(3) Installation and/or
Modification of Oil
and Gas Facilities 09/20/95 07/26/95  Initial adoption of §116.617(3)

Section

116.620 Installation and/or
Modification of Oil
and Gas Facilities 04/19/96 03/27/96  Deleted §116.617(3) and moved Standard Permit to newly adopted §116.620

o Moving the Standard Permit from a

paragraph to a section required renumbering to conform to Texas Register style conventions

7/22/98 06/17/98  Revisions to §116.620(a)(4)

 Revisions to §116.620(a)(13)

 §116.620(a)(14) was subdivided into

sections 116.620(a)(14) – (15)

 Added §116.620(a)(16)

 Renumbered §116.620(a)(15) – (16) to

§116.620(a)(17) and (18)

 Revisions to §116.620(b)(1) added

reference to PBR 106.476

 Revisions to §116.620(c)(1)(A)

# Technical Support Document
Revisions to Texas New Source Review State Im plementation Plan Related to the Standard

Permit for Installation and/or Modification of Oil and Gas Facilities and to the Standard Permit Applicability Provisions 30 TAC Chapter 116, Subchapter F, Section 6 10, Paragraphs a and b, Section 617, Paragraph 3, and Section 620 (30 TAC 116.610(a) and (b), 116.617(3), and 116.620)

4 Section Title Date
submitted

to EPA Adopted by State Comments

 Revisions to §116.620(c)(1)(J)

 Revisions to §116.620(c)(2)(J)

 Revisions to §116.620(d)(3)

 Revisions to §116.620(e)(1)

09/11/00 04/07/00  Revisions to §116.620(a)(4)

 Revisions to §116.620(a)(11)

 Revisions to §116.620(b)(1)

 Revisions to §116.620(b)(E)

 Revisions to §116.620(c)(1)(J)



# III. Proposed Revisions to the Standard Permit Applicability Provisions

On February 1, 2006, and March 11, 2011, the St ate of Texas submitted revisions to the Standard Permit SIP rules, which included non- substantive revisions to the applicability provisions in 30 TAC 116.610(a) and (b). The revisions to these paragraphs included changes such as defining previously unde fined acronyms, changing capitalization, rephrasing of rule language, and updating or de leting cross-references as appropriate due
to revisions to other Sections of the stat e regulations. Based on our review of the proposed changes, we propose to find these changes to 30 TAC 116.610( a) and (b) to be approvable because they are minister ial and non-substantive in nature.

IV. Summary of the Oil and Gas Standard Permit

A. General Description of the Texas Standard Permits Program

EPA approved Texas’ general regulati ons for Standard Permits in 30 TAC Subchapter F of 30 TAC Chapter 116 on November 14, 2003 (68 FR 64543) as meeting the federal requirements for Minor NSR. 1 

# The November 14, 2003 action describes how those rules meet EPA’s requi rements for new minor sources and minor
modifications. A Standard Permit is a Mi nor NSR permit that is adopted under Chapter 116, Subchapter F. Subchapter F provides an alternative process for approving the construction of certain categ ories of new and modified sources for which TCEQ has adopted a Standard Permit. These provisions provide for a streamlined Minor NSR mechanism for authorizing the construction of certain sources within source categories for which TCEQ has adopted a Standard Permit. A

1 

## EPA did not approve the Standard Permit for Installation and/or Modification of Oil and Gas Facilities in the November 14, 2003, action as part of the Texas SIP (68 FR 64543, at 64547).

# Technical Support Document
Revisions to Texas New Source Review State Im plementation Plan Related to the Standard

Permit for Installation and/or Modification of Oil and Gas Facilities and to the Standard Permit Applicability Provisions 30 TAC Chapter 116, Subchapter F, Section 6 10, Paragraphs a and b, Section 617, Paragraph 3, and Section 620 (30 TAC 116.610(a) and (b), 116.617(3), and 116.620)

5 Standard Permit is not availa ble to a facility or group of facilities that undergo a change that constitutes a new major source or major modification under Title I of the Act, part C (Prevention of Significant De terioration of Air Qu ality) or part D (Nonattainment Review). Such major source or major modification must comply with the applicable permitting requirements under Chapter 116, Subchapter B, which meet the NSR requirements in Title I, part C or part D of the Act. A facility that qualifies
for a Minor NSR Standard Permit must also comply with all applicable provisions of Section 111 of the Act (NSPS) and Section 112 of the Act (NESHAP). Furthermore, a facility that qualifies for a Minor NSR Sta ndard Permit must comply with all rules and regulations of TCEQ.

A Standard Permit is not a case-by-case Minor NSR SIP permit, but rather it is a streamlined mechanism with all permitting requirements for construction and operation of a certain source category. Therefore, each Standard Permit approved in a
SIP must contain all terms and conditions on the face of it (com bined with the SIP general requirements), and it cannot be used to address s ite-specific determinations.

B. Description of the Oil and Gas Permit

The Oil and Gas Standard Permit was developed to provide a streamlined permitting process for oil and gas facilities. The Standard Permit contained in 30 TAC 116.620 simplifies the permit review process for these facilities by establishing standardized conditions applicable to the oil and gas industry, which help to streamline the agency review process and allow mo re rapid approval than would be possible under case-bycase Minor NSR review permitting.

The standardized conditions contained in the Oil and Gas Standard Permit include emission specifications, control requirements , inspection requirements, approved test methods provisions, and monitoring and reco rdkeeping requirements. In addition, a source applying for authorization unde r 30 TAC 116.620 must also meet the applicable requirements contained in th e other Sections under 30 TAC Chapter 116, Subchapter F – Standard Permits, which in clude registration and fee requirements and general permit conditions for Standard Permits. In accordance with 30 TAC 116.610(b), the Oil and Gas Standard Permit is limited to Minor NSR and cannot be used to authorize a project that constitutes a new major stationary source or major modification. Therefore, as discussed in this document, the Oil and Gas Standard Permit provisions are evaluated with respect to the applicable Minor NSR requirements.

As previously mentioned, the Oil and Ga s Standard Permit in cludes standardized
conditions for the emission units located at oil and gas facilities that may be authorized by the Standard Permit. The types of emission units that may be

# Technical Support Document
Revisions to Texas New Source Review State Im plementation Plan Related to the Standard

Permit for Installation and/or Modification of Oil and Gas Facilities and to the Standard Permit Applicability Provisions 30 TAC Chapter 116, Subchapter F, Section 6 10, Paragraphs a and b, Section 617, Paragraph 3, and Section 620 (30 TAC 116.610(a) and (b), 116.617(3), and 116.620)

6 authorized by the Standard Permit are the following:

 Internal combustion engines (ICEs),

 Natural gas turbines (NG turbines),

 Flares,

 Other combustion units (design heat input > 40 million Btu per hour),

 Natural gas glycol dehydration units,

 Storage tanks,

 Separators,

 Condensers,

 Vapor recovery units,

 Process vents, and

 Process fugitives (including process pipelines, flanges, pumps, and compressors).

This list of emission units re flects the named units found in the Oil and Gas Standard Permit. As stated in the previous Secti on, the Oil and Gas Standard Permit cannot be used to address site-specific determinations or to authorize thos e emission units that are not specifically named, and therefore, not covered by the Standard Permit. As discussed below, emission units that ar e not contained on this list may not be authorized by the Oil and Gas Standard Permit. Instead, the pe rmit applicant would
need to obtain authorization for those em ission units via a separate SIP-approved Minor NSR permitting mechanism.

In order for one of the previously-liste d emission units to be authorized by the Standard Permit, that unit must meet th e applicable unit-sp ecific standardized conditions, and, the oil and gas facility as a whole must m eet any applicable site-wide
standardized conditions contai ned in the Standard Permit. If a proposed project at an oil and gas facility includes any emission units that are not explicitly covered by the Oil and Gas Standard Permit, the permit applicant would turn to another type of Standard Permit authorization or a perm it-by-rule (PBR) or, if necessary, case-bycase NSR permitting for authorization. For example, the Oil and Gas Standard Permit does not provide authorization for cooling to wers. Therefore, an oil and gas facility with a cooling tower on-site would not be ab le to use the Oil and Gas Standard Permit
to authorize the emissions from that emi ssion unit, but could rely upon the separate cooling tower Standard Permit or PBR. 2 

# Any other emission units not specifically
authorized under the Oil and Gas Standard Permit also could obtain authorization

2 

## For example, cooling towers, including those located at oil and gas facilities, that meet all of the applicable PBR requirements may be authorized under the SIP-approved Cooling-Water Unit PBR found at 30 TAC 106.371.

# Technical Support Document
Revisions to Texas New Source Review State Im plementation Plan Related to the Standard

Permit for Installation and/or Modification of Oil and Gas Facilities and to the Standard Permit Applicability Provisions 30 TAC Chapter 116, Subchapter F, Section 6 10, Paragraphs a and b, Section 617, Paragraph 3, and Section 620 (30 TAC 116.610(a) and (b), 116.617(3), and 116.620)

7through either a Standard Permit or PBR that explicitly addresses it or obtain a caseby-case Minor NSR permit. In addition to coo ling towers, other examples of emission units that may be found at o il and gas facilities that ar e not covered by the Oil and Gas Standard Permit include, but are not limited to, truck loading emissions, heat exchangers, amine sweetening units , and sulfur recovery units. 3,4



# If the TCEQ were found to be misapplyi ng the Oil and Gas St andard Permit or a permittee obtained authorization under this Standard Permit for emission units that are outside the scope of 116.620, then EPA woul d interpret such action as a violation of the Minor NSR program in the Texas SI P. EPA or the public could address this implementation failure on a permit specific basis or other CAA remedy mechanism, such as a finding of failure to implement.

V. General Discussion of EPA’s Evaluation of the Oil and Gas Standard Permit Regulations

The SIP revisions related to the Oil and Gas Standard Permit are reviewed for compliance with the requirements of the CAA and 40 CFR part 51 – Requireme nts for Preparation, Adoption, and Submittal of Implementation Plans.

3 

## Sources may utilize SIP-approved Standard Permits or PBRs for these sources if they m eet all of the applicable requirements (e.g., Organic and Inorganic Liquid Loading and Unloading PBR found at 30 TAC 116.372 or Organic Liquid Loading and Unloading PBR found at 30 TAC 116.373 to authorize truck loading and/or sulfur recovery units). Sources may also obtain a case -by-case Minor NSR permit for these, and other sources, not covered by the
Oil and Gas Standard Permit.

4 

## While, as discussed in our proposed rulemaking, EPA finds that the provisions in 30 TAC 116.620 are approvable for authorizing certain emission units at oil and gas fac ilities in Texas, EPA recognizes that Texas also has a nonrule Standard Permit for oil and gas facilities in its SIP for facilities located in the Barnett Shale region. Beginning March 2010, TCEQ began the process of developing a new Standard Permit for oil and gas facilities. The new Standard Permit was initially going to replace the St andard Permit in the SIP submittal being addressed in this action. TCEQ adopted the new standard permit for o il and gas facilities on January 26, 2011 with applicability limited to the Barnett Shale region. When it was adopted, it was adopted as a non-rule standard permit. Upon adoption, the non-rule standard permit for Oil and Gas Facilities automatically became a part of the approved Texas SIP [30 TAC §116.601(a)(2) approved at 68 FR 64543]. We note that the non-rule Oil and Gas Standard Permit may be utilized in lieu of 30 TAC 116.620 by facilities lo cated outside the Barnett Shale, and it provides control technology requirements (e.g., emission limits, operationa l limits, design capacity, or State BACT) for additional emission units not covered by the Standard Permit under review in this action. EPA finds that this non-rule Standard Permit is more robust and more reflective of the current oil and gas industry, as compared to the Standard Permit under review in this action. Therefore, we believe that the non-rule Standard Permit’s applicability should be expanded to ap ply statewide as the oil and gas industry continues to evolve and experience significant growth in geographic area s in Texas located outside the Barnett Shale. The nonrule standard permit is a more detailed permit, with improved control requirements, monitoring, testing, and recordkeeping. It clearly identifies the emission units that can be covered, including those not covered in the 30 TAC 116.620 Standard Permit, and requires all sources to use standardized methodologies to establish emission
limits.

# Technical Support Document
Revisions to Texas New Source Review State Im plementation Plan Related to the Standard

Permit for Installation and/or Modification of Oil and Gas Facilities and to the Standard Permit Applicability Provisions 30 TAC Chapter 116, Subchapter F, Section 6 10, Paragraphs a and b, Section 617, Paragraph 3, and Section 620 (30 TAC 116.610(a) and (b), 116.617(3), and 116.620)

8 The Act at Section 110(a)(2)(C) requires states to develop and submit to EPA for approval into the state SIP, preconstruction review and permitting programs applicable to certain new and modified stationary sour ces of air pollutants for attainment and nonattainment areas that cover both major and minor new sources and modifications, collectively referred to as the NSR SIP. The CAA NSR SIP program is composed of three separate programs: Prevention of Signi ficant Deterioration (PSD), Nonattainment New Source Review (NNSR), and Minor NSR.

The Minor NSR SIP program addresses construc tion or modification activities that do not emit, or have the potential to emit, beyond certain major source/major modification thresholds and thus do not qualify as “major” and applies regardless of the designation of the area in which a source is located. Any submitted SIP revision, including revisions to a Minor NSR program, must meet the applicable requirements for SIP elements in Section 110 of the Act, and be consistent with all applicable stat utory and regulatory requirements.

EPA regulations governing the criteria that st ates must satisfy for EPA approval of the NSR programs as part of the SIP are contained in 40 CFR Sections 51.160-51.166. Regulations specific to Mi nor NSR programs are contained in 40 CFR Section 51.160- 51.164. The TCEQ has developed the Oil and Gas Standard Permit as a component of the Texas Minor NSR program; therefore we will evaluate the Standard Permit as submitted on September 20, 1995; April 19, 1996; July 22, 1998; and September 11, 2000, against the federal requirements for Minor NSR programs.

40 CFR Section 51.160 establishes the requireme nts that all Minor NSR programs must meet. We will address these specific requireme nts in Section VI.A of this TSD. 40 CFR Section 51.161 establishes the public notice re quirements for Minor NSR programs. We will address the public notice requirements mo re fully in Section VI.B of this TSD. Section 51.160-51.164 requires that a SIP revision demonstrate that the adopted rules will not interfere with any applicable requireme nt concerning attainment and reasonable further progress, or any other applicable requirement of the CAA. We will address the specific requirements for permitting activities that ensure attainment more fully in
Section VI.C of this TSD.

VI. Do the State’s Submittals for the Oil and Ga s Standard Permit Meet the Applicable Federal Requirements for Minor NSR?

A. Evaluation of Minor NSR Requirements

EPA’s regulations addressing a Minor NSR program as part of a state’s SIP are included at 40 CFR 51.160, which applies to all programs under Title I of the CAA. The provisions of a Minor NSR pr ogram must provide that the permitting

# Technical Support Document
Revisions to Texas New Source Review State Im plementation Plan Related to the Standard

Permit for Installation and/or Modification of Oil and Gas Facilities and to the Standard Permit Applicability Provisions 30 TAC Chapter 116, Subchapter F, Section 6 10, Paragraphs a and b, Section 617, Paragraph 3, and Section 620 (30 TAC 116.610(a) and (b), 116.617(3), and 116.620)

9 authority will not permit the construction of a facility or modi fication that will cause a violation of applicable portions of the control strategy or interfere with attainment or maintenance of a NAAQS. To accomplish this goal, the state’s Minor NSR program must include the m eans by which the state agency will review and take final action on proposed new construction or modification to be protective of the control strategy and NAAQS. As stated in 40 CFR 51.160, all NSR programs, including the Minor NSR program, must include legally
enforceable 5 

# procedures that meet the following requirements:

 Provide for the submission, by the ow ner or operator of the building, facility, structure or installation to be constructed or modified of such information on the nature and amounts of emissions to be emitted by it or emitted by associated mobile sources; and the design, construction and operation of such facility, building, st ructure, or installation as may be necessary to allow the permitting authority to make a determination on approvability. 40 CFR 51.160(c).

 The Minor NSR program must provide that approval of any construction
or modification must not affect the re sponsibility of the owner or operator to comply with applicable porti ons of the control strategy. 40 CFR 51.160(d).

 The Minor NSR program must include procedures to identify the types and sizes of facilities, buildings, structures, or installations which will be subject to review. The Minor NSR progr am must also discuss the basis for determining which facilities will be subject to review. 40 CFR 51.160(e).

 The Minor NSR program must also di scuss the air quality data and the dispersion or other air quality modeling used to meet the NSR requirements. 40 CFR 51.160(f).

In the September 23, 1987, Memorandum fr om J. Craig Po tter, Assistant Administrator for Air and Radiation, and Thomas L. Adams Jr., Assistant
Administrator for Enforcem ent and Compliance Monitoring, entitled “Review of State Implementation Plans and Revi sions for Enforceability and Legal Sufficiency” is EPA's additional guidance for interpreting the enforceability requirements found in Section 110(a )(2)(C) of the Act and 40 CFR 51.160. 6,7 

# In

5 

## A requirement is ‘‘legally enforceable’’ if some authority has the right to enforce the restriction. 67 FR 80186, at
80190.

6 

## Other relevant guidance includes: “Approaches to cr eating Federally-Enforceable Emissions Limits,” John S. Seitz, November 3, 1993; January 25, 1995 Memorandum entitled “Guidance on Enforceability Requirements for Limiting Potential to Emit through SIP and section 112 rule s and General Permits” from Kathie A. Stein, Office of Enforcement and Compliance As surance; and “Potential to Emit (PTE) Gu idance for Specific Source Categories”

# Technical Support Document
Revisions to Texas New Source Review State Im plementation Plan Related to the Standard

Permit for Installation and/or Modification of Oil and Gas Facilities and to the Standard Permit Applicability Provisions 30 TAC Chapter 116, Subchapter F, Section 6 10, Paragraphs a and b, Section 617, Paragraph 3, and Section 620 (30 TAC 116.610(a) and (b), 116.617(3), and 116.620)

10 the 1987 memorandum we explain that subm itted rules that are clearly worded, clear as to who must comply, and explic it in their applicability to regulated sources are appropriate means for ach ieving the statutory enforcement requirement. Appropriate testing, reco rdkeeping, reporting, and monitoring provisions are necessary to establish how compliance will be determined and be sufficient to ensure that the NAAQS and PSD increments are protected.

The SIP submittals being evaluated as part of this action are for a Standard Permit that is submitted as part of Texas’s Mi nor NSR program; therefore, the provisions
from the Oil and Gas Standard Perm it are evaluated against the federal requirements for Minor NSR and in conjunction with the existing SIP-approved provisions of the Standard Permittin g Program found in 30 TAC Chapter 116, Subchapter F – Standard Permits that provides the basic requirements that a facility must meet to qualif y for a Standard Permit.

Based on our evaluation, we propose to find that the Oil and Gas Standard Permit provisions found in 30 TAC 116.620 provide for the necessary procedures and applicable requirements that are required for Minor permitting programs.

In accordance with 30 TAC 116.611, sources seeking authorization via the Oil and Gas Standard Permit are required to submit a Standard Permit registration to TCEQ, which is to include information regarding the propos ed project to be authorized (e.g., emission estimates, descri ption of project a nd related process, description of equipment being inst alled). 30 TAC 116.615 includes general conditions that must be met by sources authorized via a Standard Permit, including the Oil and Gas St andard Permit. These gene ral conditions specifically require that sources authorized under a St andard Permit comply with all “rules, regulations, and orders of the commission issued in conformity with the [Texas Clean Air Act].” In the case where more than one state or federal rule of

Memorandum from John S. Seitz, OAQPS, and Eric Schaffer, OECA, April 14, 1998.

7 

## Practical enforceability for a source-s pecific permit will be achieved if the permit’s provisions specify: (1) A technically-accurate limitation and the portions of the source subject to the li mitation; (2) the time period for the limitation (hourly, daily, monthly, and annual limits such as rolling annual limits); and (3) the method to determine compliance, including appropriate monitoring, recordkeepin g, and reporting. For rules and general permits that apply to categories of sources, practi cable enforceability additionally requires that the provisions : (1) Identify the types or categories of sources that are covered by the rule; (2) where coverage is optional, provide for notice to the permitting authority of the source’s election to be covered by the rule; and (3) specify th e enforcement consequences relevant to the rule. (See See memorandum, “Release of Interim Policy on Federal Enforceability of Limitations on Potential to Emit,” signed by John Seitz and Robert Van Heuvelen, Jan. 22, 1996 at 5–6 and Attachment 4.) The Agency has frequently used the term “practicably enfo rceable” and “practical enfo rceability,” interchangeably. There is no difference in the meaning of these terms. ‘‘Enforceable as a practical matter’’ will be achieved if a requirement is both legally and practically enforceable. 67 FR 80186, at 80190-91.

# Technical Support Document
Revisions to Texas New Source Review State Im plementation Plan Related to the Standard

Permit for Installation and/or Modification of Oil and Gas Facilities and to the Standard Permit Applicability Provisions 30 TAC Chapter 116, Subchapter F, Section 6 10, Paragraphs a and b, Section 617, Paragraph 3, and Section 620 (30 TAC 116.610(a) and (b), 116.617(3), and 116.620)

11 regulation or permit condition are applicable, the source must comply with the most stringent requirement or limit. See 30 TAC 116.615(10) . Therefore, the
conditions of the Standard Permit in no wa y supersede or relax other applicable state or federal requirements. In additi on, the provisions found in the Oil and Gas
Standard Permit under 30 TAC 116.620 also re quire that sources authorized under the Standard Permit submit appropriate do cumentation to demonstrate compliance with state and federal provisions, in cluding PSD, NNSR, NSPS, and NESHAP. The Standard Permit also requires that new or increased emissions authorized under the permit shall not cause or cont ribute to a violatio n of any NAAQS and references that engineering judgment and/ or air dispersion modeling may be used to demonstrate NAAQS compliance for the specific minor construction project. See 30 TAC 116.620(a)(13)-(17). Regarding te sting, recordkeeping, reporting and monitoring provisions, the Oil and Gas Sta ndard Permit contains provisions that include these requirements for the emission units that can be author ized under the Standard Permit. See 30 TAC 116.620(c)-(e).

As discussed in this TSD, the Oil a nd Gas Standard Permit may be used to authorize only those emission units that are specifically cove red by the Standard Permit provisions. Our proposed approval of the Oil and Gas Standard Permit reflects this limitation in the scope regarding the emission units that may be authorized under the Standard Permit. EPA would interpret the use of the Oil and
Gas Standard Permit to authorize add itional emission units beyond the scope of the rule as circumvention of the Minor NSR program in the Texas SIP. EPA or the public could address this implementation failure on a permit specific basis or other CAA remedy mechanism, such as a finding of failure to implement. The following paragraph further explains our basis for limiting the approval of the Oil and Gas Standard Permit to the specific covered emission units, which are listed
in Section IV.B of this TSD.

If the Oil and Gas Standard Permit is used to authorize emission units other than the ones specifically covered by the Sta ndard Permit provisions, the Standard Permit would not meet the requirement that all permits must be enforceable. Clear limits on operation and/or emissions fo r all sources seeking coverage are necessary to meet the requirement of enforceability under 40 CFR 51.160(a). Section 110(a)(2)(A) states that plan s shall include enforceable emission limitations and other control measures, m eans, or techniques. For those emission units not specifically covered by the pr ovisions of the Oil and Gas Standard Permit, the Standard Permit does not provi de necessary operation and/or emission limits. As discussed previous ly, the types of uncovered emission units that may be found at an oil and gas facility include cooling towers, truck loading emissions,

# Technical Support Document
Revisions to Texas New Source Review State Im plementation Plan Related to the Standard

Permit for Installation and/or Modification of Oil and Gas Facilities and to the Standard Permit Applicability Provisions 30 TAC Chapter 116, Subchapter F, Section 6 10, Paragraphs a and b, Section 617, Paragraph 3, and Section 620 (30 TAC 116.610(a) and (b), 116.617(3), and 116.620)

12 heat exchangers, amine sweetening units, and sulfur recovery units. For these emission units, the Standard Permit fails to provide clearly identifiable operational limits or emission limits. Ther efore, these emission units are not included in the scope of the emission units that may be authorized under the Oil and Gas Standard Permit. Our proposed approval specifically excludes these emission units, as well as, any other em ission units not included in the covered
units list included in Section IV.B of this TSD. If one of these emission units is located at an oil and gas facility seeki ng NSR authorization under the Oil and Gas Standard Permit, the applicant would need to seek separate authorization for the uncovered emission units through a separate Minor NSR permitting mechanism (e.g., a PBR, a different Standard Permit, or a case-by-case Minor NSR permit).

Also note that the definiti on of Oil and Gas facility at §116.14(2) (SIP approved) states “For the purposes of Subchapter F of this chapter only, shall be defined as facilities which handle gases and liquids associated with the production, conditioning, processing, a nd pipeline transfer of fl uids found in geologic
formations beneath the earth's surface. Th ese oil and gas facil ities include, but are
not limited to: oil or gas production facilities; water injection facilities; carbon dioxide separation facilities; or oil or gas pipeline facilities consisting of one or more tanks, separators, dehydration units , free water knock-outs, gunbarrels, heater treaters, vapor recovery units, fl ares, pumps, internal combustion engines, gas turbines, compressors, natural gas liq uid recovery units, or gas sweetening and other gas conditioning facilities. This definition does not include sulfur recovery units.” The definition does not en compass all the emission units that can be found at an oil and gas facility, and the definition does not necessarily prohibit any emission unit other than sulfur recovery units. The definition may allow a source to make its own determination of what may be permitted by allowing the
statement “but are not limited to” in th e definition. The definition also includes “gas sweetening and other gas conditioning facilities.” Gas sweetening and gas conditioning facilities can cover a vari ety of processes including solid bed absorption, amine treaters, usage of chem ical solvents and physical solvents, molecular sieves and other treatment processes. 8 

# The provisions in 30 TAC 116.620 do not provide requirements for all of these types of units. Therefore, as discussed previously, the Oil and Gas St andard Permit is not adequate to
authorize these units and some other t ype of SIP-approved permitting mechanism
should be obtained.

Keeping in mind that our proposed approval of the Oil and Gas Standard Permit is

8 

## Kruse, C. F. 1974; Plant Processing of Natural Gas . Austin: The University of Texas, 1974.

# Technical Support Document
Revisions to Texas New Source Review State Im plementation Plan Related to the Standard

Permit for Installation and/or Modification of Oil and Gas Facilities and to the Standard Permit Applicability Provisions 30 TAC Chapter 116, Subchapter F, Section 6 10, Paragraphs a and b, Section 617, Paragraph 3, and Section 620 (30 TAC 116.610(a) and (b), 116.617(3), and 116.620)

13 narrowed to include the aut horization of emissions from only the named covered emission units, based on our evaluation of the proposed provisions found in the Standard Permit, in conjunction with th e underlying SIP-approved provisions of the Texas Standard Permitting Program found in Chapter 116, Subchapter F, we propose to find that the Oil and Gas Standard Permit meets the Minor NSR requirements for the units for which it is applicable.

B. Evaluation of Public Availability of Information Requirements for Minor NSR

Federal requirements for public notice of Minor NSR programs are found at 40 CFR 51.160 and 51.161. The procedures fo r a Minor NSR program in 40 CFR 51.160 require an opportunity for public comment on information submitted by the permit applicant and on the permitting authority’s analysis of the application, submitted materials and proposed approval or disapproval of the permit application. EPA further explains at 40 CFR 51.161(b) that opportunity for public comment is, at a minimum, the availabili ty for public inspection in at least one
location in the area affected of the information submitted by the owner/operator and of the permitting authority’s analysis of the effect on air quality; a 30-day period for submittal of public comment; a nd a notice by prominent advertisement in the area affected of the location where the public can see the submitted materials and analysis. The SIP submittals being evaluated as part of this action are for a Standard Permit; therefore, the provisions from the Oil and Gas Standard Permit are evaluated against the federal requirements regard ing public notice in conjunction with the existing SIP-approve d provisions of the Standard Permits Program found in 30 TAC Chapter 116, Subchapter F – Standard Permits that provide the basic requirements that a facil ity must meet to qualify for a Standard Permit, including public participa tion requirements. See 30 TAC 116.603.

Based on our evaluation, we propose to find that the SIP’s general provisions for
all Standard Permits found at 30 TAC 116.603 apply to the Oil and Gas Standard Permit. These general provisions were found to meet EPA’s requirements for public participation for Minor NSR permits and in some cases are more stringent. (73 FR 53716, September 17, 2008) As required by 30 TAC 116.603, a Standard Permit must comply with the following public notice requirements:

 Notice of a proposed Standard Permit is required to be published in the Texas Register , the commission’s publicly acc essible electronic media, and in a daily or weekly newspaper of general circulation in the area affected by the activity that is subject to the proposed permit. If the proposed Standard Permit will have stat ewide applicability , notice will be published in the daily newspaper of la rgest general circulation within each

# Technical Support Document
Revisions to Texas New Source Review State Im plementation Plan Related to the Standard

Permit for Installation and/or Modification of Oil and Gas Facilities and to the Standard Permit Applicability Provisions 30 TAC Chapter 116, Subchapter F, Section 6 10, Paragraphs a and b, Section 617, Paragraph 3, and Section 620 (30 TAC 116.610(a) and (b), 116.617(3), and 116.620)

14 of the following metropolitan areas: Austin, Dallas, and Houston and any other regional newspapers designate d by the executive director on a caseby-case basis. Additionally, the co mmission will publis h notice in the Texas Register and i ssue a press release;

 The notice must provide for a public comment period on the proposed Standard Permit of at least 30 days;

 A public meeting is required to be held to provide an additional opportunity for public comment;

 Written responses must be prepared to all public comments received from the public related to the issuance of a Standard Permit, which will be made available to the public;

 Notice of the final action on the proposed Standard Permit is required to be published in the Texas Register, in cluding the text of the response to comments; and

 Copies of the final issued Standa rd Permit along with the response to public comments received on the draft permit are required to be made available at the TCEQ Austin office and appropriate TCEQ regional
offices.

Subsequent amendments or revocation of an issued Standard Permit must also meet the public notice procedures contai ned in Section 603, as required by 30
TAC 116.605.

Based on our evaluation of the proposed provisions found in the Oil and Gas Standard Permit, as well as the underlyi ng SIP-approved provisions of the Texas Standard Permitting Program found in Chap ter 116, Subchapter F, we propose to
find that the Oil and Gas Standard Permit meets the federal public notice requirements that are applicable to Minor NSR for those emission units that are specifically covered by the Standard Permit provisions. In addition, Texas has provided documentation within their SIP revision submittals to document that the SIP-approved public notice process was fo llowed consistent with the 30 TAC 116.603 requirements when the Oil and Gas Standard Permit was initially issued and subsequently amended. The SIP submittals are available in the docket accompanying this action.

C. Evaluation of SIP Revisions with Resp ect to Attainment, Reasonable Further Progress, and Other Applicable Requirements of the Act

# Technical Support Document
Revisions to Texas New Source Review State Im plementation Plan Related to the Standard

Permit for Installation and/or Modification of Oil and Gas Facilities and to the Standard Permit Applicability Provisions 30 TAC Chapter 116, Subchapter F, Section 6 10, Paragraphs a and b, Section 617, Paragraph 3, and Section 620 (30 TAC 116.610(a) and (b), 116.617(3), and 116.620)

15 Section 110(l) of the CAA states:

Each revision to an implemen tation plan submitted by a State under this Act shall be adopted by such State after reasonable notice and public hearing. The Admi nistrator shall not approve a revision of a plan if the revision would interfere with any applicable requirement concer ning attainment and reasonable further progress (as defined in Section 171), or any other applicable requirement of this Act.

Thus, under Section 110(l), the regulations submitted as SIP revisions establishing the Oil and Gas Standard Permit must meet the procedural requirements of Section 110(l) by demonstrating that the State followed all necessary procedural requirements such as providing reasonabl e notice and public hearing of the SIP revision. Additionally, the SIP revision must demonstrate that the adopted rules will not interfere with any applicable requirement concerning attainment and reasonable further progress, or any other applicable requirement of the CAA. We propose to find that the TCEQ satisfied al l procedural requirements pursuant to Section 110(l).

A Minor NSR program is a requirement of the CAA and EPA’s regulations at 40 CFR 51.160-1.164. As discussed in this TSD, EPA proposes that the Oil and Gas Standard Permit as submitted on September 20, 1995, and revised through SIP submittals dated April 19, 1996; July 22, 1998; and September 11, 2000, satisfies the minimum requirements for a Minor NSR program, including adequate provisions for legal enforceability and public participation to ensure protection of the control strategy and a ny applicable NAAQS. The Oil and Gas Standard Permit also contains sufficient safeguards to prevent circumvention of Major NSR permitting requirements. Therefore, we propose to find that the Oil and Gas Standard Permit is protective of the NAA QS and applicable control strategy requirements and satisfies the require ments of 110(l) of the Act.

D. Summary of EPA’s Evaluation

As discussed above, EPA proposed to find that the Oil and Gas Standard Permit, as submitted on September 20, 1995, and revisions submitted on April 19, 1996; July 22, 1998; and September 11, 2000, is limited to Minor NSR. EPA proposes to find that the program satisfies the federal requirements for Minor NSR and contains sufficient enforceable safeguards to ensure that the NAAQS and applicable control stra tegies are protected.

# Technical Support Document Appendix A Part 51, Appendix V Evaluation Evaluation of the September 20, 1995; April 19, 1996; July 22, 1998; September 11, 2000; February 1, 2006; and March 11, 2011 SIP Submittals with respect to Part 51, Appendix V

i Part 51, Appendix V Completeness Checklist

The criteria for completeness determination ar e found in Appendix V to Part 51 – Criteria for determining the completeness of plan submissions and are outlined below:

1.0 Purpose: This appendix V sets forth the mi nimum criteria for determining whether a state implementation plan submitted for consideration by EPA is an official submission for purposes of review under § 51.103.

1.1 The EPA shall return to the submitting official any plan or revision thereof which fails to meet the criteria set forth in this appendi x V, and request corre ctive action, identifying the component(s) absent or insufficient to perform a review of the submitted plan.

1.2 The EPA shall inform the submitting official whether or not a plan submission meets the requirements of this appendix V within 60 days of EPA’s receipt of the submittal, but no later than 6 months after the date which the State was required to submit the plan or revision. If a completeness de termination is not made by 6 months from receipt of a submittal, the submittal shall be deemed complete by operation of law on the date 6 months from receipt. A determination of co mpleteness under this paragraph means that
the submission is an official submission for purposes of § 51.103.

The attached checklist outlines the basic crit eria included under 2.1, 2.2, and 2.3 of Appendix V.

# Technical Support Document Appendix A Part 51, Appendix V Evaluation Evaluation of the September 20, 1995; April 19, 1996; July 22, 1998; September 11, 2000; February 1, 2006; and March 11, 2011 SIP Submittals with respect to Part 51, Appendix V

ii Administrative Materials (2.1)

1. The package is sent with a formal submitta l letter from the Governor or his or her designee requesting EPA’s approval of the revision.

The SIP revisions addressed in this action were submitted via le tters from Governor George W. Bush, TCEQ Chairman Kathleen Harnett White, and TCEQ Chairman Bryan Shaw, dated September 20, 1995; April 19, 1996; July 22, 1998; September 11, 2000; February 1, 2006; and March 11, 2011.

2. Evidence is included that the State has adopted the revision in the St ate code or body of regulations, or that the State has issued the permit, order, consent agreement (hereafter document) in final form. This evidence w ould include the date of adoption or final
issuance and the effective date of revision, if different from the adoption/issuance date.

The SIP revisions addressed in this action were adopted by the state as follows:

 September 20, 1995 Submittal – Adopted Ju ly 26, 1995, effective September 1, 1995;

 April 19, 1996 Submittal – Adopted March 27, 1996, effective April 19, 1996;

 July 22, 1998 Submittal – Adopted J une 17, 1998, effective July 8, 1998;

 September 11, 2000 Submittal – Adopted August 9, 2000, effective September 4, 2000;

 February 1, 2006 Submittal – Adopted January 11, 2006, effective February 1, 2006; and

 March 11, 2011 Submittal – Adopted Januar y 11, 2006, effective February 1,
2006.

3. Evidence is included that the St ate has necessary legal author ity under State law to adopt and implement the revision, e.g., a citati on of the appropriate State authority.

The authority for promulgating changes to the Texas State Implementa tion is found in the Texas Clean Air Act, Chapter 382 of the Texas Health and Safety Code.

4. A copy is included of the actual regulati on or document submitted for approval and incorporation by reference into the SIP includin g an indication of the changes made to the existing approved place where applicable. The submittal shall be a copy of the official State regulation document signed, stamped, and dated by the appropriate State official

# Technical Support Document Appendix A Part 51, Appendix V Evaluation Evaluation of the September 20, 1995; April 19, 1996; July 22, 1998; September 11, 2000; February 1, 2006; and March 11, 2011 SIP Submittals with respect to Part 51, Appendix V

iii indicating that it is fully enforceable by the St ate. The effective date of the regulation document shall, whenever possible, be indicated in the document itself.

Each of the SIP submittals included a copy of the official State regulation document.

5. Evidence is included that the State followed all of the procedural requirements of its laws and/or its constitution in the conducting a nd completing the adoption/issuance of the plan.

The SIP submittal packages include a certifi cation demonstrating the SIP submittal was developed pursuant to 40 CFR 51.104.

6. Evidence is included that public notice was given of the proposed changes consistent with the procedures approved by EPA, including the date of publication of such notice (e.g., notarized or certified copies of any pub lic notices published in newspapers). (The notice should be at least 30 days prior to the public hearing(s).

The SIP submittals addressed in this action included a summary of the Public Notices published for the rule revisions, as well as , copies showing evidence of the published notices. These public notices included info rmation regarding the public comment period and upcoming public hearings.

7. A certification is included indicating that pub lic hearing(s) was/were held in accordance with the information provided in the pub lic notice(s) and the State’s laws and constitution, if applicable.

See reporter’s certification at the end of the public hearing transcripts in each of the SIP
submittals addressed in this action.

8. A compilation of public comments and the State’s response is included.

The SIP submittals addressed in this action in cluded copies of comments received from the public on the State regulation, as well as , as the State’s responses to the comments
received.

# Technical Support Document Appendix A Part 51, Appendix V Evaluation Evaluation of the September 20, 1995; April 19, 1996; July 22, 1998; September 11, 2000; February 1, 2006; and March 11, 2011 SIP Submittals with respect to Part 51, Appendix V

iv Technical Support (2.2)

9. Identification of all regulated polluta nts affected by the revision included.

The SIP submittals address revisions to the provisions related to the Minor NSR construction permitting program; therefore, the SIP submittals have the potential to address all regulated pollutants.

10. Identification of the locations of affected sources including the EPA attainment/nonattainment designation of the lo cations and the status of the attainment plan for the affected area(s) is included.

The provisions contained in 30 TAC 116.610 can be applied statewide to facilities seeking authorization under a Standard Permit.

The provisions contained in 30 TAC 116.620 can be applied statewide to oil and gas facilities seeking authorization under a Standar d Permit. The only exception would be those facilities located in the Barnett Shale region, which would seek authorization through the non-rule Standard Permit that was adopted by Texas in 2011. The provisions related to the non-rule Standard Pe rmit are addressed in separate provisions of the state’s rules.

11. Quantifications of the changes in SIP allowa ble emissions from the affected sources is included. (Examples include estimates of changes in current actual emissions from affected sources and/or, where appropriate, qua ntification of changes in actual emissions from affected sources through calculations of the differences be tween certain baseline levels and allowable emissions anticipat ed if the revisions were approved.)

The provisions for the Standard Permit applicab ility provisions do not need to include quantification of the ch anges in SIP allowable emissions from the affected sources. These are non-substantive changes. In addition, the underlying standard permitting process addresses the permitting em issions for a given facility.

The provisions for the Oil and Gas Standard Pe rmit do not need to include quantification of the changes in SIP allowabl e emissions from the affected sources. The mechanics of the standard permitting process ensure appropr iate amounts of permitted emissions are approved.

# Technical Support Document Appendix A Part 51, Appendix V Evaluation Evaluation of the September 20, 1995; April 19, 1996; July 22, 1998; September 11, 2000; February 1, 2006; and March 11, 2011 SIP Submittals with respect to Part 51, Appendix V

v 12. Demonstration is included that the NAAQS /PSD increments/RFP demonstration and visibility as applicable would be prot ected if the revision were approved and implemented.

The proposed revisions to the Standard Permit applicability provisions are nonsubstantive in nature and; therefore, will not interfere with the attainment or reasonable further progress or any other appl icable requiremen t of the Act.

See Section VI.C of this document for more information regarding the Oil and Gas Standard Permit SIP revisions and how they me ets the Section 110(l) requirements that require the revisions not interfere with atta inment or reasonable fu rther progress or any other applicable requir ement of the Act.

13. FOR REDESIGNATIONS:

a. Is there a fully approved maintenance pl an for the primary ambient air quality standards for at least 10 years as requ ired by § 175A of the Clean Air Act?

Not applicable.

b. Are contingency measures included?

Not applicable.

14. Modeling information, if app licable, is required to s upport the proposed revision.

Modeling information is not necessa ry to support this SIP revision.

15. Evidence is included where necessary, that emission limitations are based on continuous emission reduction technology (e.g., add-on controls, industrial/ process equipment designs, reformulated materials, etc.).

Not applicable to the non-substantive changes to the Standard Permit applicability provisions.

The provisions contained in the Oil and Gas Standard Permit incl ude both emission limitations and control requirement s that must be met by any facility that is authorized
under the Standard Permit.

# Technical Support Document Appendix A Part 51, Appendix V Evaluation Evaluation of the September 20, 1995; April 19, 1996; July 22, 1998; September 11, 2000; February 1, 2006; and March 11, 2011 SIP Submittals with respect to Part 51, Appendix V

vi 16. Evidence is included indicating that a SIP re vision contains emission limitations, work practice standards and recordk eeping/reporting requirements to ensure stated emission

levels.

Not applicable to the non-substantive changes to the Standard Permit applicability provisions.

The provisions contained in 30 TAC 116.620 include emission specifications, control requirements, inspection requirements, and monitoring and recordkeeping requirements for the emission sources covered by the O il and Gas Standard Permit. These limitations and requirements become effective for a s ource when they regist er for authorization
under the Standard Permit.

17. Compliance/enforcement strategies including how compliance will be determined in practice (including at what frequency).

Not applicable to the non-substantive changes to the Standard Permit applicability provisions.

30 TAC 116.620 does not need to include co mpliance/enforcemen t strategies. Compliance/enforcement of the Oil and Gas Standard Permit will be determined on a permit-by-permit basis.

18. As appropriate, special economic and techno logical justificati ons are included per applicable EPA policies or an explanation why such justifications are not necessary should be included. For example, requests for alternative RACT may require such justification.

These justifications are not n ecessary for this SIP revision.

The September 20, 1995; April 19, 1996; July 22, 1998; September 11, 2000; February 1, 2006; and March 11, 2011 SIP submittals meet the co mpleteness criteria established in 40 CFR part 51, Appendix V.

# Technical Support Document Appendix B Annotation of 30 TAC Chapter 116, Subchapt er F, Section 610, Paragraphs a and b, Section 617, Paragraph 3 and Sect ion 620 (30 TAC 116.617(3) and 116.620)

i I. General Discussion

This Appendix contains the annotation and evaluation of SIP revisions that Texas submitted to EPA on September 20, 1995; Ap ril 19, 1996; July 22, 1998; and September 11, 2000. These SIP revisions consist of revi sions to 30 Texas Administrative Code (TAC) Chapter 116 – Control of Air Pollu tion by Permits for New Construction and
Modification.

II. Annotation Procedure

The annotation and evaluation consists of a table for each section that is submitted. Below is a description of how each table is organized.

A. Section Title and indication of SIP Approval Status and Pending SIP Revisions

1. Above each table is the title of each section.

2. Below the title are notes which indicate the following:

3. Indication whether EPA has approved a pr ior version of th e section. If the prior version is currently SIP a pproved, we identify the following:

i. The Federal Register page numbe r and date of the latest SIP approval, the version of the Stat e rule that is approved, and the effective date of the SIP approval action; and

ii. The version of the State rule th at is approved by the date of adoption by the State and the date th e rule was effective as a State
rule.

4. Identification of all pending SIP revisi ons considered in this action, which
include:

i. The date submitted;

ii. The date adopted by the State; and

iii. The date the rule was effective as a State rule.

B. Evaluation Matrix

1. Organization of Each Table:

Each row is the annotation of each subsection, paragraph, subparagraph,
etc. or each section. Each row is di vided into two or more columns which show a separate annotation of each individual SIP revision that is
reviewed in this evaluation. Above each column is the date of the SIP revisions for which the changes are shown. The column at the far right of each row provides comments that summ arize the proposed SIP revisions.

# Technical Support Document Appendix B Annotation of 30 TAC Chapter 116, Subchapt er F, Section 610, Paragraphs a and b, Section 617, Paragraph 3 and Sect ion 620 (30 TAC 116.617(3) and 116.620)

ii 2. Annotation style:

(i) The far left column contains the text of the initial SIP revision,
which included the initia l adoption of the rule.

(ii) To the right of the initial SIP submitted rule is the revised rule. If
there is more than one revisi on to the rule, each revision is identified in a separate column and the revisions are placed in chronological order with the first revision placed to the immediate right of the initial submitted SIP and subsequent revisions are placed on order from left to right. If there is no existing SIP provision, the entire text is underlin ed to indicate that it is new text. If the submittal revised a previous provision, new text is
underlined and text that is removed is struck-out. In the case of multiple SIP revisions, each revisi on is annotated to compare the
revised rule to the revision th at immediately preceded that particular change.

(iii) The right-most column includes a summary of the proposed revisions of the particular provision, as well as, any additional

comments.

C. Proposed Action

This Section of the Appendix indicates our proposed action on the revisions included in the evaluation matrix, as we ll as, provides additional information regarding the basis of our proposed action.

# Technical Support Document Appendix B Annotation of 30 TAC Chapter 116, Subchapt er F, Section 610, Paragraphs a and b, Section 617, Paragraph 3 and Sect ion 620 (30 TAC 116.617(3) and 116.620)

iii 30 TAC 116.610. Applicability

I. Background of 30 TAC 116.610.

A. Current SIP: The current SIP-approved version of 116.610 was adopted by TNRCC March 7, 2001 (effective March 29, 2001). EP A approved this version of 116.610 into the Texas SIP on September 6, 2006 (eff ective October 6, 2006; 71 FR 52664). The current SIP contains paragra phs a, b, and c of Section 160. 116.610(d) is not approved
into the SIP.

B. Pending SIP Revisions Reviewed in this Action:

1. February 1, 2006: Texas revised §116.610, adopted January 11, 2006; effective February 1, 2006.

2. March 11, 2011: Resubmittal of revisions to §116.610, January 11, 2006; effective February 1, 2006.

II. Evaluation matrix.

Annotation and Evaluation of §116.610 Comments

Current SIP a) Under the TCAA, §382.051, a project which meets

the requirements for a standard permit listed in this subchapter or issued by the commission is hereby entitled to the standard permit, provided the following conditions listed in this section are met. For the purposes of this subchapter, project means
the construction or modifi cation of a facility or a group of facilities submitted under the same registration: Rev submitted 02/01/2006 (Res ubmitted on 03/11/2011) a) Under the Texas Clean Air Act TCAA , §382.051, a project that which meets the requirements for a standard permit listed in this subchapter or issued by the commission is hereby entitled to the standard permit, provided the following conditions listed in this section are met. For the purposes of this subchapter, project
means the construction or modi fication of a facility or a group of facilities submitted under the same registration: Revision 02/01/06

 Revisions are nonsubstantive to update formatting requirements

Current SIP

1) any project which results in a net increase in

emissions of air contaminants from the project other than carbon dioxide, water, nitrogen, methane, ethane, hydrogen, oxygen, or those for which a National Ambient Air Quality Standard
has been established must meet the emission limitations of §106.261(3) or (4) or §106.262(3) of this title (relating to Facilities (Emission Limitations), and Facilities (Emission and Distance Limitations)), unless otherwise specified by a particul ar standard permit; Rev submitted 02/01/2006 (Res ubmitted on 03/11/2011) 1)Any any project that which results in a net increase in

emissions of air contaminan ts from the project other than carbon dioxide, water, nitrogen, methane, ethane, hydrogen, oxygen, or those for which a National Ambient Air Quality Standard has been
established must meet the emission limitations of §106.261 §106.261(3) or (4) or §106.262(3) of this title (relating to Facilities (Emission Limitations), and Facilities (Emission and Distance Limitations)), unless otherwise specified by a particular standard permit. ; Revision 02/01/06

 Revisions are nonsubstantive to update formatting requirements and to update internal
cross references

Current SIP

2) construction or operation of the project must be

commenced prior to the effective date of a revision to this subchapter under which the project would no longer meet the requirements for a standard permit; Rev submitted 02/01/2006 (Res ubmitted on 03/11/2011) 2) Construction construction or operation of the project

must be commenced prior to the effective date of a revision to this subchapter under which the project would no longer meet the requirements for a standard permit. ; Revision 02/01/06

 Revisions are nonsubstantive to update formatting requirements

Current SIP

3) the proposed project must comply with the

applicable provisions of the FCAA, §111 (concerning New Source Performance Standards) as listed under Title 40 Code of Federal Regulations (CFR) Part 60, promulgated by the EPA; Rev submitted 02/01/2006 (Res ubmitted on 03/11/2011) 3) The the proposed project must comply with the

applicable provisions of the Federal Clean Air Act ( FCAA) , §111 (concerning New Source Performance Standards) as listed under Title 40 Code of Federal Regulations (CFR) Part 60, promulgated by the United States Environmental Protection Agency ( EPA). ; Revision 02/01/06

 Revisions are nonsubstantive to update formatting requirements

# Technical Support Document Appendix B Annotation of 30 TAC Chapter 116, Subchapt er F, Section 610, Paragraphs a and b, Section 617, Paragraph 3 and Sect ion 620 (30 TAC 116.617(3) and 116.620)

iv Annotation and Evaluation of §116.610 Comments

Current SIP

4) the proposed project must comply with the

applicable provisions of FCAA, §112 (concerning Hazardous Air Pollutants) as listed under 40 CFR 61, promulgated by the EPA; Rev submitted 02/01/2006 (Res ubmitted on 03/11/2011) 4)The the proposed project must comply with the

applicable provisions of FCAA, §112 (concerning Hazardous Air Pollutants) as listed under 40 CFR

Part 61, promulgated by the EPA. ; Revision 02/01/06

 Revisions are nonsubstantive to update formatting requirements

Current SIP

5) the proposed project must comply with the

applicable maximum achievable control technology standards as listed under 40 CFR Part 63, promulgated by the EPA under FCAA, §112 or as listed under Chapter 113, Subchapter C of this title (relating to National Emissions
Standards for Hazardous Air Pollutants for Source Categories (FCAA, §112, 40 CFR 63));
and Rev submitted 02/01/2006 (Res ubmitted on 03/11/2011) 5) The the proposed project must comply with the

applicable maximum achievable control technology standards as listed under 40 CFR Part 63, promulgated by the EPA under FCAA, §112 or as listed under Chapter 113, Subchapter C of this title (relating to National Emissions Standards for Hazardous Air Pollutants for Source Categories (FCAA, §112, 40 CFR Part 63)). ; and Revision 02/01/06

 Revisions are nonsubstantive to update formatting requirements

Current SIP

6) If subject to Chapter 101, Subchapter H,

Division 3 of this title (relating to Mass Emissions Cap and Trade Program) the proposed facility, group of facilities, or account must obtain allocations to operate. Rev submitted 02/01/2006 (Res ubmitted on 03/11/2011) No changes submitted. Revision 02/01/06 No changes

Current SIP b) Any project, except those authorized under

§116.617 of this title (relating to Standard Permits for Pollution Control Projects), which constitutes a new major source, or major modification under the new source review requirements of the FCAA, Part C (Prevention of Significan t Deterioration Review) or Part D (Nonattainment Review) and regulations promulgated thereunder is subject to the requirements of §116.110 of this title (relating to Applicability) rather than this subchapter. Rev submitted 02/01/2006 (Res ubmitted on 03/11/2011) b) Any project that constitutes a new major stationary

source or major modification as defined in §116.12 of this title (relating to Nonattainment and Prevention of Significant Deterioration Review Definitions) is subject to the requirements of § 116.110 of this title (relating to Applicability) rather than this subchapter. , except those authorized under §116.617 of this title (relating to Standard Permits for Pollution Control Projects), which constitutes a new major source, or major modification
under the new source r eview requirements of the FCAA, Part C (Prevention of Signi ficant Deterioration Review) or Part D (Nonattainment Review) and regulations promulgated thereunder is subject to the requirements of §116.110 of this title (relati ng to Applicability) rather
than this subchapter. Revision 02/01/06

 Revisions are nonsubstantive to update internal
cross references

Current SIP c) Persons may not circumvent by artificial

limitations the requirements of §116.110 of this
title. Rev submitted 02/01/2006 (Res ubmitted on 03/11/2011) No changes submitted. Revision 02/01/06

 No changes

Current SIP d) NOT in SIP Rev submitted 02/01/2006 (Res ubmitted on 03/11/2011)
Not submitted to SIP Revision 02/01/06

 Not submitted to
SIP



# III. Proposed Action.

Approval of the non-substantive revisi ons to 30 TAC 116.610 February 1, 2006, and March 11, 2011. Based on our review of the pr oposed changes, we propose to find these changes to 30 TAC 116.610(a) and (b) to be ap provable because they are ministerial and
non-substantive in nature.

# Technical Support Document Appendix B Annotation of 30 TAC Chapter 116, Subchapt er F, Section 610, Paragraphs a and b, Section 617, Paragraph 3 and Sect ion 620 (30 TAC 116.617(3) and 116.620)

v 30 TAC 116.620. Installation and/or Modifi cation of Oil and Gas Facilities. (Initially adopted at 30 TAC 116.617(3))

I. Background of 30 TAC 116.620.

A. Current SIP: §116.620 is not currently approved as part of the Texas SIP.

B. Pending SIP Revisions Reviewed in this Action:

1. September 20. 1995: Texas submitted new §116.617(3), adopted July 26, 1995; effective September 1, 1995.

2. April 19, 1996: Texas deleted §116.617( 3) and moved Standard Permit to§116.620 with revisions, adopted March 27, 1996; effective April 19, 1996.

3. July 22, 1998: Texas revised §116.620, adopted June 17, 1998; effective July 8,
1998.

4. September 11, 2000: Texas revised §116.620, adopted August 9, 2000; effective September 4, 2000.

II. Evaluation matrix.

Annotation and Evaluation of §116.620 Comments

Submitted 09/20/95 §116.617(3). Installation and/or Modification of
Oil and Gas Facilities. Rev submitted 04/19/1996 §116.620. Installation and/or Modification of Oil and
Gas Facilities. Revision 04/19/96

 116.617(3) deleted
and section moved
to new section
116.620

 Changed section designations when moved to comply
with section numbering.

Submitted 09/20/95 (A) Emission Specifications Rev submitted 04/19/1996 (a) Emission Specifications Revision 04/19/96

 Changed section designations when moved to comply
with section numbering.

Submitted 09/20/95 (i) Venting or flaring more than 0.3 long tons per day of total sulfur shall not be allowed. (ii) No Facility shall be allowed to emit total uncontrolled emissions of sulfur compounds, except sulfur dioxide (SO 2 ), from all vents (excluding process fugitives emissions) equal to or greater than four pounds per hour unless vapors are collected and routed to a flare. (iii) Any vent, excluding any safety relief valves that discharge to the atmosphere only as a result of fire or failure of utilities, emitting sulfur compounds other than sulfur dioxide shall be at least 20 feet above ground level. Rev submitted 04/19/1996 (1) Venting or flaring more than 0.3 long tons per day of
total sulfur shall not be allowed. (2) No Facility shall be allowed to emit total uncontrolled emissions of sulfur compounds, except sulfur dioxide (SO 2 ), from all vents (excluding process fugitives emissions) equal to or greater than four pounds per hour unless vapors are collected and
routed to a flare. (3) Any vent, excluding any safety relief valves that discharge to the atmosphere only as a result of fire or failure of utilities, emitting sulfur compounds other
than sulfur dioxide SO 2 shall be at least 20 feet above ground level. Revision 04/19/96

 Changed section designations when moved to comply
with section numbering.

# Technical Support Document Appendix B Annotation of 30 TAC Chapter 116, Subchapt er F, Section 610, Paragraphs a and b, Section 617, Paragraph 3 and Sect ion 620 (30 TAC 116.617(3) and 116.620)

vi Annotation and Evaluation of §116.620 Comments

Submitted 09/20/95 (iv) New or modified
internal combustion reciprocating engines or gas turbines permitted
under this standard permit shall satisfy all the requirements
of Standard Exemption Number 6, except that registration using
form PI-7 or PI-8 shall not be required.
Emissions from engines or turbines
shall be limited to
the amounts found in §116.211(a)(1) of this title (relating to Standard Exemption List). Rev submitted
04/19/1996 (4) New or modified
internal combustion reciprocating engines

or gas turbines permitted under this standard permit shall satisfy all the requirements of Standard Exemption Number 6, except that registration using
form PI-7 or PI-8 shall not be required.
Emissions from engines or turbines
shall be limited to the
amounts found in §116.211(a)(1) of this title (relating to Standard Exemption List). Rev submitted
07/22/1998 (4) New or modified
internal
combustion reciprocating engines or gas turbines permitted
under this standard permit shall satisfy
all of the requirements of
Standard Exemption
Number 6 §106.512 of this title (relating to Stationary Engines
and Turbines (Previously SE 6)) , except that registration using
the Form PI-7 or
PI-8 shall not be required.
Emissions from engines or turbines
shall be limited to
the amounts found in §116.211
106.4 (a)(1) of this title (relating to
Standard Exemption List Requirements for Exemption from Permitting ). Rev submitted 09/11/2000 (4) New or modified internal combustion reciprocating engines or gas turbines permitted under this standard permit shall satisfy all of the requirements of §106.512 of this title (relating to Stationary Engines and Turbines (Previously SE 6) ), except that registration using the
Form PI-7 or PI-8 shall not be required. Emissions from engines or turbines
shall be limited to the amounts found in § 106.4(a)(1) of this title (relating to Requirements for Exemption f rom Permitting by Rule ). Revision 04/19/96

 Changed section designations when moved to comply
with section numbering.
Revisions 07/22/98
and 09/11/00

 Revisions updated
the reference from
standard exemption to permit by rule.

# Technical Support Document Appendix B Annotation of 30 TAC Chapter 116, Subchapt er F, Section 610, Paragraphs a and b, Section 617, Paragraph 3 and Sect ion 620 (30 TAC 116.617(3) and 116.620)

vii Annotation and Evaluation of §116.620 Comments

Submitted 09/20/95 (v) Total Volatile Organic Compound (VOC) emissions from a natural gas glycol dehydration unit shall not exceed ten tons per year (tpy) unless the vapors are collected and controlled in accordance with subparagraph (B)(ii) of this paragraph. (vi) Any combustion unit (excluding flares, internal combustion engines, or natural gas turbines), with a design maximum heat input greater than 40 million British thermal units (Btu) per hour (using lower heating values) shall not emit more than 0.06 pounds of nitrogen oxides (NO

x ) per
million Btu. (vii) No facility which is less than 500 feet from the nearest off-plant receptor shall be allowed to emit uncontrolled VOC process fugitive emissions equal to or greater than ten tpy, but less than 25 tpy, unless the equipment is inspected and repaired according to subparagraph (C)(i) of this paragraph. (viii) No facility which is 500 feet or more from the nearest off-plant receptor shall be allowed to emit uncontrolled VOC process fugitive emissions equal to or greater than 25 tpy unless the equipment is inspected and repaired according to subparagraph (C)(i) of this paragraph. (ix) No facility which is less than 500 feet from the nearest off-plant receptor shall be allowed to emit uncontrolled VOC process fugitive emissions equal to or greater than 25 tpy unless the equipment is inspected and repaired according to subparagraph (C)(ii) of this paragraph. (x) No facility shall be allowed to emit uncontrolled VOC process fugitive emissions equal to or greater than 40 tpy unless the equipment is inspected and repaired according to subparagraph (C)(ii) of this paragraph. Rev submitted 04/19/1996 (5) Total Volatile Organic Compound (VOC) emissions from a natural gas glycol dehydration unit shall not exceed ten tons per year (tpy) unless the vapors are
collected and controlle d in accordance with subparagraph subsection (B b )(ii 2 ) of this paragraph
section

. (6) Any combustion unit (excluding flares, internal combustion engines, or natural gas turbines), with a design maximum heat input greater than 40 million British thermal units (Btu) per hour (using lower heating values) shall not emit more than 0.06 pounds of nitrogen oxides (NO

x ) per million Btu. (7) No facility which is less than 500 feet from the nearest off-plant receptor sh all be allowed to emit uncontrolled VOC process fugitive emissions equal to or greater than ten tpy, but less than 25 tpy, unless the equipment is inspected and repaired according to subparagraph subsection (C c )(i 1 ) of this paragraph
section

. (8) No facility which is 500 feet or more from the nearest off-plant receptor shall be allowed to emit uncontrolled VOC process fugitive emissions equal to or greater than 25 tpy unless the equipment is inspected and repaired according to subparagraph
subsection (C c )(i 1 ) of this paragraph section

. (9) No facility which is less than 500 feet from the nearest off-plant receptor sh all be allowed to emit uncontrolled VOC process fugitive emissions equal to or greater than 25 tpy unless the equipment is inspected and repaired according to subparagraph
subsection (C c )(ii 2 ) of this paragraph section

. (10) No facility shall be a llowed to emit uncontrolled VOC process fugitive emissions equal to or greater than 40 tpy unless the equipment is inspected and repaired according to subparagraph subsection (C

c )(ii 2 ) of this paragraph section

. Revision 04/19/96

 Changed section designations when moved to comply
with section numbering.

# Technical Support Document Appendix B Annotation of 30 TAC Chapter 116, Subchapt er F, Section 610, Paragraphs a and b, Section 617, Paragraph 3 and Sect ion 620 (30 TAC 116.617(3) and 116.620)

viii Annotation and Evaluation of §116.620 Comments

Submitted 09/20/95 (xi) No facility which is
located less than one quarter of a mile from the nearest off-plant receptor
shall be allowed to emit hydrogen sulfide (H 2 S) or
SO 2 process fugitive
emissions unless the equipment is inspected and repaired according to subsection (C)(iii) of this paragraph. No facility
which is located at least one quarter of a mile from the nearest off-plant receptor shall be allowed
to emit H 2 S or SO 2 process fugitive emissions unless the equipment is inspected and repaired according to subparagraph (C)(iii) of this paragraph or unless the

H 2 S or SO 2 emissions are
monitored with ambient property line monitors according to subparagraph (E)(i) of this paragraph. Components in sweet crude oil or gas service as defined by Chapter 101 of this title (relating to General Rules) are exempt
from these limitations. Rev submitted 04/19/1996 (11) No facility which is located less than one quarter of a 1⁄4
mile from the nearest offplant receptor shall be allowed to emit hydrogen sulfide (H 2 S) or SO 2 process fugitive emissions unless the equipment is inspected and repaired according to subparagraph subsection (C

c )(iii 3 ) of this paragraph section. No facility which
is located at least one quarter of a 1⁄4 mile from the nearest off-plant receptor shall be allowed to
emit H 2 S or SO 2 process fugitive emissions unless the equipment is inspected and repaired according to subparagraph subsection (C

c )(iii 3 ) of this paragraph or
section unless the H 2 S or
SO 2 emissions are
monitored with ambient property line monitors according to subparagraph subsection (E e)(i 1) of this

parag raph section. Components in sweet crude oil or gas service as defined by Chapter 101 of this title (relating to General Rules) are exempt from these
limitations. Rev submitted 09/11/2000 (11) No facility which is located less than 1⁄4 mile from the nearest off-plant receptor shall be allowed to emit hydrogen sulfide ( H 2 S) or SO 2 process fugitive emissions unless the equipment is inspected and repaired according to subsection (c)(3) of this section. No facility which is located
at least 1⁄4 mile from the nearest offplant receptor shall be allowed to
emit H 2 S or SO 2 process fugitive emissions unless the equipment is inspected and repaired according to subsection (c)(3) of this section
unless the H 2 S or SO 2 emissions are monitored with ambient property line monitors according to subsection (e)(1) of this section. Components in sweet crude oil or gas service as defined by Chapter 101 of this title (relating to General Rules) are exempt from these
limitations. Revision 04/19/96

 Changed section designations when moved to comply
with section numbering.
Revision 09/11/00

 Revision
eliminated parenthesis around

H 2 S in the first

sentence.

Submitted 09/20/95 (xii) Flares shall be designed and operated in
accordance with 40 Code of Federal Regulations (CFR), Part 60.18 or equivalent standard approved by the commission, including specifications of minimum heating values of waste gas, maximum tip velocity, and pilot flame monitoring. If necessary to ensure adequate combustion, sufficient gas shall be added to make the gases combustible. An
infrared monitor is cons idered equivalent to a thermocouple for flame monitoring purposes. An automatic ignition system may be used in lieu of a continuous pilot. Rev submitted 04/19/1996 (12) Flares shall be designed and operated in accordance with 40 Code of Federal Regulations (CFR), Part 60.18 or equivalent sta ndard approved by the commission, including specifications of minimum heating values of waste gas, maximum tip velocity, and pilot flame monitoring. If necessary to ensure adequate combustion, sufficie nt gas shall be added to make the gases combustible. An infrared monitor is considered equivalent to a thermocouple for flame monitoring purposes. An automatic ignition system may be used in lieu of a continuous pilot. Revision 04/19/96

 Changed section designations when moved to comply
with section numbering.

# Technical Support Document Appendix B Annotation of 30 TAC Chapter 116, Subchapt er F, Section 610, Paragraphs a and b, Section 617, Paragraph 3 and Sect ion 620 (30 TAC 116.617(3) and 116.620)

ix Annotation and Evaluation of §116.620 Comments

Submitted 09/20/95 (xiii) Appropriate documentation
shall be submitted to demonstrate that compliance
with the Prevention of Significant Deterioration (PSD) and nonattainment new source review (NSR) provisions of the FCAA, Parts C and D, and regulations promulgated thereunder, are being met. The oil and gas facility shall be required to meet the requirements of Subchapter B of the chapter (relating to
New Source Review Permits) instead of this subchapter if a PSD or nonattainment permit is required. (xiv) Documentation shall be
submitted to demonstrate compliance with applicable
New Source Performance Standards (NSPS, 40 CFR 60) and National Emission
Standards for Hazardous Air Pollution (NESHAP, 40 CFR 61). Rev submitted 04/19/1996 (13) Appropriate
documentation shall be
submitted to demonstrate that compliance with the Prevention of Significant Deterioration (PSD) and
nonattainment new source review (NSR) provisions
of the FCAA Federal Clean Air Act, Parts C and D, and regulations promulgated thereunder, are being met. The oil and gas facility shall be required to meet the requirements of Subchapter B of the this chapter (relating to New Source Review Permits) instead of this subchapter
if a PSD or nonattainment permit is required. (14) Documentation shall be
submitted to demonstrate compliance with applicable New Source
Performance Standards (NSPS, 40 CFR 60) and
National Emission
Standards for Hazardous Air Pollution (NESHAP, 40 CFR 61). Rev submitted 07/22/1998 (13) Appropriate documentation shall be
submitted to demonstrate that compliance with the Prevention of Significant Deterioration (PSD) and
nonattainment new source review provisions of the Federal Clean Air
Act FCAA , Parts C and D, and regulations promulgated thereunder, and with Subchapter C of this chapter (relating to Hazardous Air Pollutants: Regulations Governing Constructed or Reconstructed Major Sources (FCAA, §112(g), 40 CFR Part 63)) are being met. The oil and gas facility shall be required to meet the requirements of Subchapter B of this chapter (relating to New Source Review Permits) instead of this subchapter if a PSD or nonattainment permit or a review under Subchapter C of this chapter is required. (14) Documentation shall be submitted to demonstrate compliance with applicable New Source Performance Standards (NSPS, 40 CFR Part 60).

a nd National Emission Standards for Hazardous Air Pollution (NESHAP, 40 CFR 61). Revision 04/19/96

 Changed section designations when moved to comply
with section numbering.
Revision 07/22/98

 Revision to (13):
Added reference to Subchapter C and
40 CFR Part 63 for compliance and
review under Subchapter C for major sources.

 Revision to (14): Separated NSPS
and NESHAP requirements into separate sections.

# Technical Support Document Appendix B Annotation of 30 TAC Chapter 116, Subchapt er F, Section 610, Paragraphs a and b, Section 617, Paragraph 3 and Sect ion 620 (30 TAC 116.617(3) and 116.620)

x Annotation and Evaluation of §116.620 Comments

Submitted 09/20/95 (xv) New and increased
emissions shall not cause or
contribute to a violation of any National Ambient Air Quality Standard (NAAQS) or regulation property line standards as specified in Chapters 111, 112, and 113 of this title (relating to
Control of Air Pollution
From Visible Emissions and Particulate Matter; Control
of Air Pollution From Sulfur Compounds; and Control of
Air Pollution From Toxic Materials). Engineering judgment and/or computerized air dispersion modeling may be used in
this demonstration. To show compliance with § 116.610(a)(1) of this title (relating to Applicability)
for H 2 S emissions from
process vents, ten milligrams per cubic meter
shall be used as the “L”
value instead of the value represented by §116.610(a)(1) of this title. Rev submitted 04/19/1996 (15) New and increased
emissions shall not cause
or contribute to a violation of any National Ambient Air Quality Standard (NAAQS) or regulation property line standards as specified in Chapters 111, 112, and 113 of this title (relating to Control of Air
Pollution From Visible
Emissions and Particulate Matter; Control of Air
Pollution From Sulfur Compounds; and Control
of Air Pollution From Toxic Materials). Engineering judgment and/or computerized air dispersion modeling may
be used in this
demonstration. To show compliance with § 116.610(a)(1) of this title (relating to Applicability)
for H 2 S emissions from
process vents, ten milligrams per cubic meter
shall be used as the “L”
value instead of the value represented by §116.610(a)(1) of this title. Rev submitted 07/22/1998 (15) Documentation shall be submitted to demonstrate compliance with applicable National Emission
Standards for Hazardous Air Pollution (NESHAP, 40 CFR Part 61). (16) Documentation shall be submitted to demonstrate compliance with applicable maximum achievable control technology standards as listed under 40 CFR Part 63, promulgated by the EPA under FCAA, §112 or as listed in Chapter 113, Subchapter C of this title (relating to National Emissions
Standards for Hazardous Air Pollutants for Source Categories (FCAA §112, 40 CFR Part 63)). (17) (15) New and increased emissions
shall not cause or contribute to a violation of any National Ambient Air Quality Standard or regulation property line standards as specified in Chapters 111, 112, and 113 of this title (relating to Control of Air
Pollution From Visible Emissions and Particulate Matter; Control of
Air Pollution From Sulfur Compounds; and Control of Air Pollution From Toxic Materials). Engineering judgment and/or computerized air dispersion modeling may be used in this demonstration. To show compliance with §116.610(a)(1) of this title (relating to Applicability) for H 2 S emissions from process vents, ten milligrams per cubic meter shall be
used as the “L” value instead of the value represented by §116.610(a)(1)
of this title. Revision 04/19/96

 Changed section designations when moved to comply
with section numbering.
Revision 07/22/98

 Revised (15):
Created a new
section for
NESHAP compliance

 Revised (16):
Created a new
section for MACT requirements

 Revised (17):Was originally (15), no changes made to the language

# Technical Support Document Appendix B Annotation of 30 TAC Chapter 116, Subchapt er F, Section 610, Paragraphs a and b, Section 617, Paragraph 3 and Sect ion 620 (30 TAC 116.617(3) and 116.620)

xi Annotation and Evaluation of §116.620 Comments

Submitted 09/20/95 (xvi) Fuel for all combustion units and flare pilots shall be sweet natural gas or liquid petroleum gas, fuel gas containing no more than ten grains of total sulfur per 100 dry standard cubic feet (scdf), or field gas. If field gas contains more than 1.5 grains of H 2 S or 30 grains total sulfur compounds per 100 scdf, the operator shall maintain records, including at least quarterly measurements of
fuel H 2 S and total sulfur content, which demonstrate
that the annual SO 2 emissions from the facility
do not exceed the
limitations listed in the standard permit registration. If a flare is the only combustion unit on a property, the operator shall not be required to maintain such records on flare pilot

gas. Rev submitted 04/19/1996 (16) Fuel for all combustion units and flare pilots shall be sweet natural gas or liquid petroleum gas, fuel gas containing no more than ten grains of total sulfur per 100 dry standard cubic feet (scdf), or field gas. If field gas contains more than 1.5 grains of H 2 S or 30 grains total sulfur compounds per 100 scdf, the operator shall maintain records, including at least quarterly measurements of
fuel H 2 S and total sulfur content, which demonstrate
that the annual SO 2 emissions from the facility
do not exceed the
limitations listed in the standard permit registration. If a flare is the only combustion unit on a property, the operator shall not be required to maintain such records on flare pilot

gas. Rev submitted 07/22/1998 (18) (16) Fuel for all combustion units and flare pilots shall be sweet natural gas or liquid petroleum gas, fuel gas containing no more than ten grains of total sulfur per 100 dry standard cubic feet (scdf dscf), or field gas. If field gas contains more than 1.5 grains of H 2 S or 30 grains total sulfur compounds per 100 scdf dscf, the operator shall maintain records including at least quarterly
measurements of fuel H 2 S and total sulfur content, which demonstrate
that the annual SO 2 emissions from the facility do not exceed the
limitations listed in the standard permit registration. If a flare is the only combustion unit on a property, the operator shall not be required to maintain such records on flare pilot

gas. Revision 04/19/96

 Changed section designations when moved to comply
with section numbering.
Revision 07/22/98

 Revision corrected the acronym for dry standard cubic
feet from scdf to
dscf.

 Section
renumbered from
addition of
addition sections
above.

Submitted 09/20/95 (B) Control requirements Rev submitted 04/19/1996 (B) (b) Control requirements Revision 04/19/96

 Changed section designations when moved to comply
with section numbering.

# Technical Support Document Appendix B Annotation of 30 TAC Chapter 116, Subchapt er F, Section 610, Paragraphs a and b, Section 617, Paragraph 3 and Sect ion 620 (30 TAC 116.617(3) and 116.620)

xii Annotation and Evaluation of §116.620 Comments

Submitted 09/20/95 (1) (i) Floating roofs or equivalent
controls shall be required on all
new or modified storage tanks,
other than pressurized tanks
which meet
Standard Exemption 83,
unless the tank is less than 25,000 gallons in nominal size or the vapor pressure of the compound to be
stored in the tank
is less than 0.5 pounds per square
inch absolute (psia) at maximum short-term storage
temperature. Rev submitted
04/19/1996 (1) Floating roofs or equivalent controls shall be required
on all new or modified storage tanks, other than pressurized tanks
which meet
Standard Exemption 83,
unless the tank is less than 25,000 gallons in nominal size or the vapor pressure of the compound to be
stored in the tank is
less than 0.5 pounds per square inch absolute (psia)
at maximum shortterm storage temperature. Rev submitted
07/22/1998 (1) Floating roofs or equivalent controls shall be required on
all new or modified storage tanks, other than pressurized
tanks which meet Standard Exemption
83 §106.476 of this title (relating to
Pressurized Tanks
or Tanks Vented to Control (Previously SE 83)) , unless the
tank is less than 25,000 gallons in
nominal size or the vapor pressure of the compound to be
stored in the tank is less than 0.5 pounds per square inch absolute (psia) at
maximum shortterm storage temperature. Rev submitted 09/11/2000 (1) Floating roofs or equivalent controls shall be required on all new or modified storage tanks, other than pressurized tanks which meet §106.476 of this title (relating to
Pressurized Tanks or Tanks
Vented to Control (Previously SE 83) ), unless the tank is less than 25,000 gallons in nominal size or the vapor pressure of the compound to be stored in the tank is less than 0.5 pounds per square inch absolute(psia) at maximum shortterm storage temperature. Revision 04/19/96

 Changed section designations when moved to comply
with section numbering.
Revision 07/22/98 and
09/11/00

 Revisions changed
reference from
Standard Exemptions to Permits by Rule

Submitted 09/20/95 (I) For internal floating roofs, mechanical shoe primary seal or liquid-mounted primary seal or a vapor-mounted primary with rim-mounted secondary seal shall be used. (II) Mechanical shoe or liquid-mounted primary seals shall include a rim-mounted secondaryseal on all external floating roofs tanks. Vapormounted primary seals will not be accepted. (III) All floating roof tanks shall comply with the requirements under §115.112(a)(2)(A)-(F) of this title (relating to Control Requirements). (IV) In lieu of a floating roof, tank emissions may be
routed to: (-a-) A destruction device such that a minimum VOC destruction efficiency of 95% is achieved; or (-b-) A vapor recovery system such that a minimum VOC recovery efficiency of
95% is achieved. Rev submitted 04/19/1996 (A) For internal floating roofs, mechanical shoe primaryseal or liquid-mounted primary seal or a vapormounted primary with rim-mounted secondary seal
shall be used. (B) Mechanical shoe or liquid-mounted primary seals shall include a rim-mounted secondary seal on all external floating roofs tanks. Vapor-mounted primary seals will not be accepted. (C) All floating roof tanks shall comply with the requirements under §115.112(a)(2)(A)-(F) of this title (relating to Control Requirements). (D) In lieu of a floating roof, tank emissions may be
routed to: (i) A destruction device such that a minimum VOC destruction efficiency of 95% is achieved; or (ii) A vapor recovery system such that a minimum VOC recovery efficiency of 95% is achieved. Revision 04/19/96

 Changed section designations when moved to comply
with section numbering.

# Technical Support Document Appendix B Annotation of 30 TAC Chapter 116, Subchapt er F, Section 610, Paragraphs a and b, Section 617, Paragraph 3 and Sect ion 620 (30 TAC 116.617(3) and 116.620)

xiii Annotation and Evaluation of §116.620 Comments

Submitted 09/20/95 (I) Independent of the exemptions listed in the paragraph, if the emissions from any fixed roof tank exceeded ten tpy of VOC or ten tpy of sulfur compounds, the tank
emissions shall be routed to a destruction device, vapor recovery unit, or equivalent method of
control that meets the requirements listed in subclause (VI) of this
clause. Rev submitted 04/19/1996 (E) Independent of the exemptions listed in the paragraph, if the emissions from any fixed roof tank exceeded ten tpy of VOC or ten tpy of sulfur compounds, the tank
emissions shall be routed to a destruction device, vapor recovery unit, or equivalent
method of control that meets the requirements listed in subclause (VI) subparagraph (D) of this
clause paragraph

. Rev submitted 09/11/2000 (E) Independent of the exemptions permits by rule listed in the this paragraph, if the emissions from any fixed roof tank exceeded ten tpy of VOC or ten tpy of sulfur compounds, the tank emissions shall be routed to a destruction device, vapor recovery unit, or equivalent
method of control that meets the requirements listed in subparagraph (D) of this paragraph. Revision 04/19/96

 Changed section designations when moved to comply
with section numbering.
Revision 09/11/00

 Revision changed
reference from
standard exemption to permit by rule.

Submitted 09/20/95 (ii) The VOC emissions from a natural gas glycol dehydration unit shall be controlled as follows. (I) If total uncontrolled VOC emissions are equal to or greater than ten tpy, but less than 50 tpy, a minimum of 80% by weight minimum control efficiency shall be achieved by either operating a condenser and a separator (or flash tank), vapor recovery unit, destruction device, or equivalent control device. (II) If total uncontrolled VOC emissions are equal to or greater than 50 tpy, a
minimum of: (-a-) 98% by weight minimum destruction efficiency shall be achieved by a destruction device or equivalent; or (-b-) 95% by weight minimum control efficiency shall be achieved by a
vapor recovery system or equivalent. Rev submitted 04/19/1996 (2) The VOC emissions from a natural gas glycol dehydration unit shall be controlled as follows. (A) If total uncontrolled VOC emissions are equal to or greater than ten tpy, but less than 50 tpy, a minimum of 80% by weight minimum control efficiency shall be achieved by either operating a condenser and a separato r (or flash tank), vapor recovery unit, destructi on device, or equivalent
control device. (B) If total uncontrolled VOC emissions are equal to or greater than 50 tpy, a minimum of: (i) 98% by weight minimum destruction efficiency shall be achieved by a destruction device or equivalent; or (ii) 95% by weight minimum control efficiency shall be achieved by a vapor recovery system or equivalent. Revision 04/19/96

 Changed section designations when moved to comply
with section numbering.

Submitted 09/20/95 (C) Inspection requirements. Rev submitted 04/19/1996 (C) (c) Inspection requirements. Revision 04/19/96

 Changed section designations when moved to comply
with section numbering.

# Technical Support Document Appendix B Annotation of 30 TAC Chapter 116, Subchapt er F, Section 610, Paragraphs a and b, Section 617, Paragraph 3 and Sect ion 620 (30 TAC 116.617(3) and 116.620)

xiv Annotation and Evaluation of §116.620 Comments

Submitted 09/20/95 (i) Owners or operators who are

subject to subparagraph (A)(vii) or (viii) of this paragraph shall comply with the following requirements.

(I) No component shall be

allowed to have a VOC leak for more than 15 days after
the leak is detected to
exceed a VOC concentration greater than 10,000 parts per million by volume (ppmv) above background as methane, propane, or hexane, or the dripping or exuding of process fluid based on sight, smell, or sound for all components. The VOC fugitive emission components which contact process fluids where the VOCs have an aggregate partial pressure or vapor pressure of less than 0.5 psia at 100 degrees Fahrenheit are exempt from this requirement. If VOC fugitive emission components are in service where the operating pressure is at least 0.725 pounds per square inch (psi) (five kilopascals (Kpa)) below ambient pressure, then these components are also exempt from this requirement as long as the equipment is
identified in a list that is made available upon request by Texas Natural Resource
Conservation Commission (TNRCC) representatives, the EPA, or any other air pollution agency having jurisdiction. All piping and
valves two inches nominal size and smaller, unless subject to federal New
Source Performance Standards requiring a fugitive VOC emissions leak detection and repair program or Chapter 115 of this title (relating to Control of Air
Pollution from Volatile Organic Compounds), are also exempt from this requirement. Rev submitted 04/19/1996 (1) Owners or operators who are

subject to subparagraph
subsection (A a )(vii 7 ) or (viii 8 ) of this paragraph section shall comply with the following requirements. (A) No component shall be
allowed to have a VOC leak for more than 15 days after
the leak is detected to exceed a VOC concentration greater than 10,000 parts per million by volume (ppmv) above background as methane, propane, or hexane, or the dripping or exuding of process fluid based on sight, smell, or sound for all components. The VOC fugitive emission components which contact process fluids
where the VOCs have an aggregate partial pressure or vapor pressure of less than 0.5 psia at 100 degrees Fahrenheit are exempt from this requirement. If VOC fugitive emission components are in service where the operating pressure is at least 0.725 pounds per square inch (psi) (five kilopascals (Kpa)) below ambient pressure, then these components are also exempt from this requirement as long as the equipment is
identified in a list that is made available upon request by

Texas Nat ural Resource
Conservation Commission (TNRCC) representatives the agency representatives , the
United States Environmental Protection Agency ( EPA) , or any other air pollution agency having jurisdiction. All piping
and valves two inches nominal size and smaller, unless subject to federal New
Source Performance
Standards NSPS requiring a fugitive VOC emissions leak detection and repair program or Chapter 115 of this title (relating to Control of Air
Pollution from Volatile Organic Compounds), are also exempt from this requirement. Rev submitted 07/22/1998 (1) Owners or operators who are subject to subsection (a)(7) or (8) of this section shall comply with the following requirements. (A) No component shall be
allowed to have a VOC leak for more than 15 days after
the leak is detected to
exceed a VOC concentration greater than 10,000 parts per million by volume (ppmv) above background as methane, propane, or hexane, or the dripping or exuding of process fluid based on sight, smell, or sound for all components. The VOC fugitive emission components which contact process fluids where the VOCs have an aggregate partial pressure or vapor pressure of less than 0.5 psia at 100 degrees Fahrenheit are exempt from this requirement. If VOC fugitive emission components are in service where the operating pressure is at least 0.725 pounds per square inch (psi) (five kilopascals (Kpa)) below ambient pressure, then these components are also exempt from this requirement as long as the equipment is
identified in a list that is made available upon request by the agency representatives, the United
States Environmental Protection Agency ( EPA)

, or any other air pollution agency having jurisdiction. All piping and valves two
inches nominal size and smaller, unless subject to federal NSPS requiring a fugitive VOC emissions leak detection and repair program or Chapter 115 of this title (relating to Control of Air
Pollution from Volatile Organic Compounds), are also exempt from this requirement. Revision 04/19/96

 Changed section designations when moved to comply
with section numbering.
Revision 07/22/98

 Revision removed
the formal name for EPA, leaving just the acronym.

# Technical Support Document Appendix B Annotation of 30 TAC Chapter 116, Subchapt er F, Section 610, Paragraphs a and b, Section 617, Paragraph 3 and Sect ion 620 (30 TAC 116.617(3) and 116.620)

xv Annotation and Evaluation of §116.620 Comments

Submitted 09/20/95 (II) All technically feasible repairs shall be made to

repair a VOC leaking process fugitive component within 15 days after the leak is detected. If the repair of a component would require a unit shutdown, the repair may be delayed until the next scheduled shutdown. All leaking co mponents which cannot be repaired until a scheduled shutdown shall be identified for such repa ir by tagging. The TNRCC executive director, at his or her discretion, may require early unit shutdow n or other appropriate action based on the number and severity of tagged leaks awaiting shutdown. (III) New and reworked underground process pipelines

containing VOCs shall contain no buried valves such that process fugitive emissi on inspection and repair is rendered impractical. (IV) To the extent that good engineering practice will

permit, new and reworked valves and piping
connections in VOC service sh all be so located to be reasonably accessible for leak-checking during plant operation. Valves elevated more than two metersabove a support surface will be considered nonaccessible and shall be identified in a list to be made available upon request. (V) New and reworked piping connections in VOC

service shall be welded or flanged. Screwed connections are permissi ble only on piping smaller
than two-inch diameter. No later than the next scheduled quarterly monitoring after initial installation or replacement , all new or reworked connections shall be gas-tested or hydraulically-tested at no less than normal operating pressure and adjustments made as necessary to obtain leak-free performance. Flanges in VOC service shall be inspected by visual, audible, and/or olfactory means at least weekly by operating personnel walk-through. (VI) Each open-ended valve or line in VOC service,

other than a valve or line us ed for safety relief, shall be equipped with a cap, b lind flange, plug, or a second valve. Except during sampling, the second
valve shall be closed. (VII) Accessible valves in VOC service shall be

monitored by leak-checking for fugitive emissions at least quarterly using an approved gas analyzer. For valves equipped with ruptur e discs, a pressure gauge
shall be installed between the relief valve and rupture disc to monitor disc integrity. All leaking discs shall be replaced at the earliest opportunity, but no later than the next process shutdown. Sealless/leakless valves (including, but not limited to, welded bonnet bellows and diaphragm valves) and relief valves equipped with a rupture disc or venting to a control device are exempt from monitoring. (VIII) Dual pump seals with barrier fluid at higher

pressure than process pressure, seals degassing to vent control systems kept in good working order, or seals equipped with an automatic seal failure detection and alarm system, submerged pumps, or sealless pumps (including, but not limited to, diaphragm, canned, or magnetic driven pumps) are exempt from monitoring. Rev submitted 04/19/1996 (B) All technically feasible repairs shall be made to

repair a VOC leaking process fugitive component within 15 days after the leak is detected. If the repair of a component would require a unit shutdown, the repair may be delayed until the next scheduled shutdown. All leaking co mponents which cannot be repaired until a scheduled shutdown shall be identified for such repa ir by tagging. The TNRCC executive director, at his or her discretion, may require early unit shutdow n or other appropriate action based on the number and severity of tagged leaks awaiting shutdown. (C) New and reworked underground process pipelines

containing VOCs shall contain no buried valves such that process fugitive emissi on inspection and repair is rendered impractical. (D) To the extent that good engineering practice will

permit, new and reworked valves and piping
connections in VOC service sh all be so located to be reasonably accessible for leak-checking during plant operation. Valves elevated more than two metersabove a support surface will be considered nonaccessible and shall be identified in a list to be made available upon request. (E) New and reworked piping connections in VOC

service shall be welded or flanged. Screwed connections are permissi ble only on piping smaller
than two-inch diameter. No later than the next scheduled quarterly monitoring after initial installation or replacement , all new or reworkedconnections shall be gas-tested or hydraulicallytested at no less than normal operating pressure and adjustments made as necessary to obtain leak-free performance. Flanges in VOC service shall be inspected by visual, audible, and/or olfactory means at least weekly by operating personnel walk-through. (F) Each open-ended valve or line in VOC service, other

than a valve or line used fo r safety relief, shall be equipped with a cap, blind flange, plug, or a second valve. Except during sampli ng, the second valve shall
be closed. (G) Accessible valves in VOC service shall be

monitored by leak-checking for fugitive emissions at least quarterly using an approved gas analyzer. For valves equipped with ruptur e discs, a pressure gauge
shall be installed between the relief valve and rupture disc to monitor disc integrity. All leaking discs shall be replaced at the earliest opportunity, but no later than the next process shutdown. Sealless/leakless valves (including, but not limited to, welded bonnet bellows and diaphragm valves) and relief valves equipped with a rupture disc or venting to a control device are exempt from monitoring. (H) Dual pump seals with barri er fluid at higher pressure

than process pressure, seals degassing to vent control systems kept in good working order, or seals equipped with an automatic seal failure detection and alarm system, submerged pumps, or sealless pumps (including, but not limited to, diaphragm, canned, or magnetic driven pumps) are exempt from monitoring. Revision 04/19/96

 Changed section designations when moved to comply
with section numbering.

# Technical Support Document Appendix B Annotation of 30 TAC Chapter 116, Subchapt er F, Section 610, Paragraphs a and b, Section 617, Paragraph 3 and Sect ion 620 (30 TAC 116.617(3) and 116.620)

xvi Annotation and Evaluation of §116.620 Comments

Submitted 09/20/95 (IX) All other pump and

compressor seals emitting VOC shall
be monitored with an approved gas analyzer at least quarterly. (X) After completion of

the required quarterly inspections for a period of at least two years, the operator of the oil and gas facility may request in writing to the TNRCC, Office of Air Quality, New
Source Review
Division that the monitoring schedule
be revised based on the percent of valves leaking. The percent of valves leaking
shall be determined by dividing the sum of valves leaking during current monitoring and
valves for which repair has been delayed by the total
number of valves subject to the requirements. This request shall include
all data that has been developed to justify the following
modifications in the monitoring schedule. Rev submitted 04/19/1996 (I) All other pump and

compressor seals emitting
VOC shall be monitored with an approved gas analyzer at least quarterly. (J) After completion of the

required quarterly inspections for a period of at least two years, the operator of the oil and gas facility may request in writing to the TNRCC, Office of Air Quality,
New Source Review
Division that the monitoring schedule be
revised based on the percent of valves leaking. The percent of valves leaking shall be determined by dividing the sum of valves leaking during current monitoring
and valves for which repair has been delayed by the total number of valves subject to the requirements. This request shall include all
data that has been developed to justify the following modifications in the monitoring
schedule. Rev submitted
07/22/1998 (I) All other pump and

compressor seals emitting VOC shall
be monitored with an approved gas analyzer at least quarterly. (J) After completion of

the required quarterly inspections for a period of at least two years, the operator of the oil and gas facility may request in writing to
the Office of Air Quality, New
Source Review
Permits Division that the monitoring
schedule be revised based on the percent of valves leaking. The percent of valves leaking shall be determined by dividing the sum of valves leaking during current monitoring and
valves for which repair has been delayed by the total
number of valves subject to the requirements. This request shall include
all data that has been developed to justify the following
modifications in the monitoring
schedule. Rev submitted 09/11/2000 (I) All other pump and compressor seals emitting VOC shall be
monitored with an approved gas analyzer at least quarterly. (J) After completion of the required quarterly inspections for a period of at least two years, the operator of the oil and gas facility may request in writing to the Office of Air Quality, New
Source Review Permits
Division Permitting, Remediation, and Registration that the monitoring schedule be
revised based on the percent of valves leaking. The percent of valves leaking shall be determined by dividing
the sum of valves leaking during current monitoring and valves for which repair has been delayed by the
total number of valves subject to the requirements. This request shall include all
data that has been developed to justify the following modifications in the monitoring
schedule. Revision 04/19/96

 Changed section designations when moved to comply
with section numbering.
Revision 07/22/98 and
09/11/00

 Revisions changed
the office name
reference.

 No change made to (I)

Submitted 09/20/95 (-a-) After two consecutive quarterly leak detection periods with the percent of valves leaking equal to or less than 2.0%, an owner or operator may begin to skip one of the quarterly leak detection periods for the valves in gas/vapor and light liquid service. (-b-) After five consecutive quarterly leak detection periods with the percent of valves leaking equal to or less than 2.0%, an owner or operator may begin to skip three of the quarterly leak detection periods for the valves in gas/vapor and light liquid
service. Rev submitted 04/19/1996 (i) After two consecutive quarterly leak detection periods with the percent of valves leaking equal to or less than 2.0%, an owner or operator may begin to skip one of the quarterly leak detection periods for the valves in gas/vapor and light liquid service. (ii) After five consecutive quarterly leak detection periods with the percent of valves leaking equal to or less than 2.0%, an owner or operator may begin to skip three of the quarterly leak detection periods for the valves in gas/vapor and light liquid
service. Revision 04/19/96

 Changed section designations when moved to comply
with section numbering.

# Technical Support Document Appendix B Annotation of 30 TAC Chapter 116, Subchapt er F, Section 610, Paragraphs a and b, Section 617, Paragraph 3 and Sect ion 620 (30 TAC 116.617(3) and 116.620)

xvii Annotation and Evaluation of §116.620 Comments

Submitted 09/20/95 (ii) Owners or operators who are subject to subsection (A)(ix) or (x) of this sec tion shall comply with the following requirements. (I) No component shall be allowed to have a VOC leak for more than 15 days after the
leak is found which exceeds a VOC concentration greater than 500 ppmv for all components except pumps and compressors and greater than 2,000 ppmv for pumps and compressors above background as methane, propane, or hexane, or the dripping or exuding of process fluid based on sight, smell, or sound. The VOC fugitive emission components which contact process fluids where the VOCs have an aggregate partial pressure or vapor pressure of less than 0.044 psia at 100 degrees Fahrenheit are exempt from this requirement. If VOC fugitive emission components are in service where the operating pressure is at least 0.725 psi (five Kpa) below ambient pressure, these components are also exempt from this requirement as long as the equipment is
identified in a list that is made available upon request by TNRCC representatives, the EPA, or any air pollution control agency having jurisdiction. All piping and valves two inches nominal size and smaller are also exempt from this requirement. (II) All technically feasible repairs shall be made to repair a VOC leaking process fugitive component within 15 days after the leak is detected. If the repair of a component would require a unit shutdown, the repair may be delayed until the next scheduled shutdown. All leaking components which cannot be repaired until a scheduled shutdown shall be
identified for such re pair by tagging. The executive director, at his or her discretion, may require early unit shutdown or other appropriate action based on the number and severity of tagged leaks awaiting shutdown. (III) New and reworked underground process pipelines containing VOCs shall contain no
buried valves such th at process fugitive emission inspection and repair is rendered impractical. (IV) To the extent that good engineering practice will permit, new and reworked valves and piping connections in VOC service shall be so located to be reasonably accessible for leak-checking during plant operation. Valves
elevated more than two meters above asupport surface will be considered nonaccessible and shall be identified in a list to be made available upon request. Rev submitted 04/19/1996 (2) Owners or operators who are subject to subsection (A a)(ix 9) or (x 10) of this section shall comply with the following requirements. (A) No component shall be allowed to have a VOC leak for more than 15 days after the
leak is found which exceeds a VOC concentration greater than 500 ppmv for all components except pumps and compressors and greater than 2,000 ppmv for pumps and compressors above background as methane, propane, or hexane, or the dripping or exuding of process fluid based on sight, smell, or sound. The VOC fugitive emission components which contact process fluids where the VOCs have an aggregate partial pressure or vapor pressure of less than 0.044 psia at 100 degrees Fahrenheit are exempt from this requirement. If VOC fugitive emission components are in service where the operating pressure is at least 0.725 psi (five Kpa) below ambient pressure, these components are also exempt from this requirement as long as the equipment is
identified in a list that is made available upon request by TNRCC agency representatives, the EPA, or any air pollution control agency having jurisdiction. All piping and valves two
inches nominal size and smaller are also exempt from this requirement. (B) All technically feasible repairs shall be made to repair a VOC leaking process fugitive component within 15 days after the leak is detected. If the repair of a component would require a unit shutdown, the repair may be delayed until the next scheduled shutdown. All leaking components which cannot be repaired until a scheduled shutdown shall be
identified for such re pair by tagging. The executive director, at his or her discretion, may require early unit shutdown or other appropriate action based on the number and severity of tagged leaks awaiting shutdown. (C) New and reworked underground process pipelines containing VOCs shall contain no
buried valves such th at process fugitive emission inspection and repair is rendered impractical. (D) To the extent that good engineering practice will permit, new and reworked valves and piping connections in VOC service shall be so located to be reasonably accessible for leak-checking during plant operation. Valves
elevated more than two meters above asupport surface will be considered nonaccessible and shall be identified in a list to be made available upon request. Revision 04/19/96

 Changed section designations when moved to comply
with section numbering.

# Technical Support Document Appendix B Annotation of 30 TAC Chapter 116, Subchapt er F, Section 610, Paragraphs a and b, Section 617, Paragraph 3 and Sect ion 620 (30 TAC 116.617(3) and 116.620)

xviii Annotation and Evaluation of §116.620 Comments

Submitted 09/20/95 (V) New and reworked piping connections in VOC service shall be welded or flanged. Screwed connections are permissi ble only on piping smaller
than two-inch diameter. No later than the next scheduled quarterly monitoring after initial installation or replacement , all new or reworkedconnections shall be gas-tested or hydraulicallytested at no less than normal operating pressureand adjustments made as necessary to obtain leakfree performance. Flanges in VOC service shall be inspected by visual, audible, and/or olfactory means at least weekly by operating personnel walk-through. (VI) Each open-ended valve or line in VOC service, other than a valve or line used for safety relief, shall be equipped with a cap , blind flange, plug, or a second valve. Except during sampling, the
second valve shall be closed. (VII) Accessible valves in VOC service shall be monitored by leak-checking for fugitive emissions at least quarterly using an approved gas analyzer. For valves equipped with rupture discs, a pressure gauge shall be installed between the relief valve and rupture disc to monitor disc integrity. All leaking discs shall be replaced at the earliest opportunity, but no later than the next process
shutdown. Sealless/leakless valves (including, but not limited to, welded bonnet bellows and diaphragm valves) and relief valves equipped with a rupture disc or venting to a control device are exempt from monitoring. (VIII) Dual pump seals with barrier fluid at higher pressure than process pressure, seals degassing to vent control systems kept in good working order or seals equipped with an automatic seal failure detection and alarm system , submerged pumps, or sealless pumps (including, but not limited to, diaphragm, canned, or magnetic driven pumps) are exempt from monitoring. (IX) All other pump and compressor seals emitting VOC shall be monitored with an approved gas analyzer at least quarterly. Rev submitted 04/19/1996 (E) New and reworked piping connections in VOC service shall be welded or flanged. Screwed connections are permissi ble only on piping smaller
than two-inch diameter. No later than the next scheduled quarterly monitoring after initial installation or replacement , all new or reworkedconnections shall be gas-tested or hydraulicallytested at no less than normal operating pressureand adjustments made as necessary to obtain leakfree performance. Flanges in VOC service shall be inspected by visual, audible, and/or olfactory means at least weekly by operating personnel walk-through. (F) Each open-ended valve or line in VOC service, other than a valve or line used for safety relief, shall be equipped with a cap , blind flange, plug, or a second valve. Except during sampling, the
second valve shall be closed. (G) Accessible valves in VOC service shall be monitored by leak-checking for fugitive emissions at least quarterly using an approved gas analyzer. For valves equipped with rupture discs, a pressure gauge shall be installed between the relief valve and rupture disc to monitor disc integrity. All leaking discs shall be replaced at the earliest opportunity, but no later than the next process
shutdown. Sealless/leakless valves (including, but not limited to, welded bonnet bellows and diaphragm valves) and relief valves equipped with a rupture disc or venting to a control device are exempt from monitoring. (H) Dual pump seals with barrier fluid at higher pressure than process pressure, seals degassing to vent control systems kept in good working order or seals equipped with an automatic seal failure detection and alarm system , submerged pumps, or sealless pumps (including, but not limited to, diaphragm, canned, or magnetic driven pumps) are exempt from monitoring. (I) All other pump and compressor seals emitting VOC shall be monitored with an approved gas analyzer at least quarterly. Revision 04/19/96

 Changed section designations when moved to comply
with section numbering.

# Technical Support Document Appendix B Annotation of 30 TAC Chapter 116, Subchapt er F, Section 610, Paragraphs a and b, Section 617, Paragraph 3 and Sect ion 620 (30 TAC 116.617(3) and 116.620)

xix Annotation and Evaluation of §116.620 Comments

Submitted 09/20/95 (X) After completion of the required quarterly inspections for a period of at least two years, the operator of the oil and gas facility may request in writing to the TNRCC, Office of Air Quality, New
Source Review Division that the monitoring
schedule be revised based on the percent of valves. Leaking. The percent of valves leaking shall be determined by dividing the sum of valves leaking during current monitoring and valves for which repair has been delayed by the
total number of valves subject to the requirements. This request shall include
all data that has been developed to justify the following modifications in the monitoring schedule. Rev submitted 04/19/1996 (J) After completion of the required quarterly inspections for a period of at least two years, the operator of the oil and gas facility may request in writing to the TNRCC, Office of Air Quality, New Source
Review Division that the monitoring schedule be revised based on the percent of valves. Leaking. The percent of valves leaking shall be determined by dividing the sum of valves leaking during current monitoring and valves for which repair has been delayed by the total number of valves subject to the requirements. This request
shall include all data that has been developed to justify the following
modifications in the monitoring schedule. Rev submitted 07/22/1998 (J) After completion of the required quarterly inspections for a period of at least two years, the operator of the oil and gas facility may request in writing to the Office of Air Quality,
New Source Review Permits Division that the monitoring
schedule be revised based on the percent of valves. Leaking. The percent of valves leaking shall be determined by dividing the sum of valves leaking during current monitoring and valves for which repair has been delayed by the total number of valves subject to the requirements. This request shall
include all data that has been developed to justify the following modifications in the monitoring
schedule. Revision 04/19/96

 Changed section designations when moved to comply
with section numbering.
Revision 07/22/98

 Revision added
Permits to the
office name

Submitted 09/20/95 (-a-) After two consecutive quarterly leak detection periods with the percent of valves leaking equal to or less than 2.0%, an owner or operator may begin to skip one of the quarterly leak detection periods for the valves in gas/vapor and light liquid service. (-b-) After five consecutive quarterly leak detection periods with the percent of valves leaking equal to or less than 2.0%, an owner or operator may begin to skip three of the quarterly leak detection periods for the valves in gas/vapor and light liquid service. Rev submitted 04/19/1996 (i) After two consecutive quarterly leak detection periods with the percent of valves leaking equal to or less than 2.0%, an owner or operator may begin to skip one of the quarterly leak detection periods for the valves in gas/vapor and light liquid service. (ii) After five consecutive quarterly leak detection periods with the percent of valves leaking equal to or less than 2.0%, an owner or operator may begin to skip three of the quarterly leak detection periods for the valves in gas/vapor and light liquid service. Revision 04/19/96

 Changed section designations when moved to comply
with section numbering.

Submitted 09/20/95 (XI) A directed maintenance program shall be used and consist of the repair and maintenance of VOC fugitive emission components assisted simultaneously by the use of an approved gas analyzer such that a minimum concentration of leaking VOC is obtained for each component being maintained. Replaced components shall be remonitored within 30 days of being placed
back into VOC service. Rev submitted 04/19/1996 (K) A directed maintenance program shall be used and consist of the repair and maintenance of VOC fugitive emission components assisted simultaneously by the use of an approved gas analyzer such that a minimum concentration of leaking VOC is obtained for each component being maintained. Replaced components shall be remonitored within 30 days of being placed
back into VOC service. Revision 04/19/96

 Changed section designations when moved to comply
with section numbering.

# Technical Support Document Appendix B Annotation of 30 TAC Chapter 116, Subchapt er F, Section 610, Paragraphs a and b, Section 617, Paragraph 3 and Sect ion 620 (30 TAC 116.617(3) and 116.620)

xx Annotation and Evaluation of §116.620 Comments

Submitted 09/20/95 (iii) For owners and operators who are subject to the applicable parts of subparagraph (A)(xi) of this paragraph, auditory and visual checks for SO 2 and H 2 S leaks within the operating area shall be made every day. Immediately, but no later than eight hours upon detection of a leak, operating personnel shall take the following actions: (I) isolate the leak; and (II) commence repair or replacement of the leaking component; or (III) use a leak collection/containment system to prevent the leak until repair or replacement can be made if immediate repair is not possible. Rev submitted 04/19/1996 (3) For owners and operators who are subject to the applicable parts of subparagraph subsection (A a )(xi
11 ) of this paragraph section , auditory and visual
checks for SO 2 and H 2 S leaks within the operating area shall be made every day. Immediately, but no later than eight hours upon detection of a leak, operating personnel shall take the following actions: (A) isolate the leak; and (B) commence repair or replacement of the leaking
component; or (C) use a leak collection/containment system to prevent the leak until repa ir or replacement can be made if immediate repair is not possible. Revision 04/19/96

 Changed section designations when moved to comply
with section numbering.

Submitted 09/20/95 (D) Approved test methods. Rev submitted 04/19/1996 (D) (d) Approved test methods. Revision 04/19/96

 Changed section designations when moved to comply
with section numbering.

Submitted 09/20/95 (i) An approved gas analyzer used for the VOC fugitive inspection and repair requirement in subparagraph (C) of this paragraph, shall conform to requirements listed in 40 CFR §60.485(a) and (b). (ii) Tutweiler analysis or equivalent shall be used to
determine the H 2 S content as required under subparagraph (A) and (E) of this paragraph Rev submitted 04/19/1996 (1) An approved gas analyzer used for the VOC fugitive inspection and repair requirement in subparagraph
subsection (C c ) of this paragraph section , shall conform to requirements listed in 40 CFR §60.485(a) and (b). (2) Tutweiler analysis or equivalent shall be used to
determine the H 2 S content as required under subparagraph subsection (A a) and (E e) of this
section. Revision 04/19/96

 Changed section designations when moved to comply
with section numbering.

# Technical Support Document Appendix B Annotation of 30 TAC Chapter 116, Subchapt er F, Section 610, Paragraphs a and b, Section 617, Paragraph 3 and Sect ion 620 (30 TAC 116.617(3) and 116.620)

xxi Annotation and Evaluation of §116.620 Comments

Submitted 09/20/95 (iii) Proper operation of any
condenser used as a VOC
emissions control device to comply with subparagraph (A)(v) of this paragraph shall be
tested to demonstrate compliance with the
minimum control efficiency. Sampling shall occur within 60 days after start-up of new or
modified facilities. The permittee shall contact the Engineering Services Section, Air Quality
Enforcement Division 45 days prior to sampling for approval of sampling protocol. The appropriate regional office in the region where the source is
located shall also be contacted 45 days prior to sampling to provide them the opportunity to view the sampling. Neither the regional office nor the Engineering Services Section, Air Quality
Enforcement Division personnel are required to view the testing. Sampling reports which comply with the provisions of the "TNRCC Sampling Procedures Manual," Chapter 14 ("Contents of Sampling Reports," dated January 1983 and revised July 1985), shall be
distributed to the appropriate regional office, any local programs, and the Engineering Services Section, Air Quality
Enforcement Division. Rev submitted 04/19/1996 (3) Proper operation of any
condenser used as a VOC
emissions control device to comply with subparagraph
subsection (A a )(v 5 ) of this paragraph section shall be
tested to demonstrate compliance with the minimum control efficiency. Sampling shall occur within 60 days after start-up of new
or modified facilities. The permittee shall contact the Engineering Services Section, Air Quality Enforcement Division 45 days prior to sampling for approval of sampling protocol. The appropriate regional office in the region where the source is
located shall also be contacted 45 days prior to sampling to provide them the opportunity to view the sampling. Neither the regional office nor the Engineering Services Section, Air Quality Enforcement Division personnel are required to view the testing. Sampling reports which comply with the provisions of the "TNRCC Sampling Procedures Manual," Chapter 14 ("Contents of Sampling Reports," dated January 1983 and revised July 1985), shall
be distributed to the appropriate regional office, any local programs, and the Engineering Services Section, Air Quality Enforcement
Division. Rev submitted 07/22/1998 (3) Proper operation of any condenser used
as a VOC emissions control device to comply with subsection (a)(5) of this
section shall be tested to demonstrate compliance with the minimum control efficiency. Sampling shall occur within 60 days after start-up of new or modified facilities. The permittee shall contact the Engineering Services Section, Air Quality Office of Compliance and Enforcement Division 45 days prior to sampling for approval of sampling protocol. The appropriate regional office in the region where the
source is located shall also be contacted 45 days prior to sampling to provide them the opportunity to view the sampling. Neither the regional office nor the Engineering Services Section, Air Quality Office of Compliance and
Enforcement Division personnel are required to view the testing. Sampling reports which comply with the provisions of the "TNRCC Sampling Procedures Manual," Chapter 14 ("Contents of Sampling Reports," dated January 1983 and revised July 1985), shall be distributed to the appropriate regional office, any local programs, and the Engineering Services Section, Air Quality Office of Compliance and
Enforcement Division

. Revision 04/19/96

 Changed section designations when moved to comply
with section numbering.
Revision 07/22/98

 Revision changed
the office name
referenced

Submitted 09/20/95 (E) Monitoring and recordkeeping requirements. Rev submitted 04/19/1996 (E) (e) Monitoring and recordkeeping requirements. Revision 04/19/96

 Changed section designations when moved to comply
with section numbering.

# Technical Support Document Appendix B Annotation of 30 TAC Chapter 116, Subchapt er F, Section 610, Paragraphs a and b, Section 617, Paragraph 3 and Sect ion 620 (30 TAC 116.617(3) and 116.620)

xxii Annotation and Evaluation of §116.620 Comments

Submitted 09/20/95 (i) If the operator elects to
install and maintain ambient

H 2 S property line monitors to comply with subparagraph (A)(xi) of this paragraph, the monitors shall be approved by the TNRCC Engineering Services Section, Air Quality Enforcement Division office in Austin, and shall be capable of detecting and alarming at

H 2 S concentrations of ten ppmv. Operations personnelshall perform an initial onsite inspection of the facility
within 24 hours of initial
alarm and take corrective
actions as listed in subparagraph (C)(iii)(I) - (III) of this paragraph within eight hours of detection of a
leak. (ii) The results of the VOC leak detection and repair requirements shall be made
available to the executive director, his or her designated representative, or any air pollution control agency having jurisdiction upon request. Records, for all components, shall
include: Rev submitted 04/19/1996 (1) If the operator elects to
install and maintain ambient

H 2 S property line monitors to comply with subparagraph subsection (A

a )(xi 11 ) of this paragraph
section , the monitors shall be approved by the TNRCC Engineering Services Section, Air Quality
Enforcement Division office in Austin, and shall be capable of detecting and alarming at H 2 S concentrations of ten ppmv. Operations personnel shall perform an initial on-site inspection of the facility
within 24 hours of initial
alarm and take corrective
actions as listed in subparagraph subsection (C

c )(iii 3 )(I A ) - (III C ) of this paragraph section within eight hours of detection of a
leak. (2) The results of the VOC leak detection and repair requirements shall be made
available to the executive director, his or her designated representative, or any air pollution control agency having jurisdiction upon request. Records, for all components, shall
include: Rev submitted 07/22/1998 (1) If the operator elects to install and
maintain ambient H 2 S property line monitors to comply with subsection (a)(11) of this section, the monitors shall be approved by the Engineering Services Section, Air Quality
Enforcement Division Office of Compliance and Enforcement in Austin, and shall be capable of detecting and alarming at H 2 S concentrations of ten ppmv. Operations personnel shall perform an initial on-site inspection of the facility
within 24 hours of initial alarm and
take corrective actions as listed in subsection (c)(3)(A) - (C) of this section within eight hours of detection
of a leak. (2) The results of the VOC leak detection and repair requirements shall be made available to the executive director, his or her designated representative, or any air pollution control agency having jurisdiction upon request. Records, for all components, shall
include: Revision 04/19/96

 Changed section designations when moved to comply
with section numbering.
Revision 07/22/98

 Revision changed
the office name
referenced

# Technical Support Document Appendix B Annotation of 30 TAC Chapter 116, Subchapt er F, Section 610, Paragraphs a and b, Section 617, Paragraph 3 and Sect ion 620 (30 TAC 116.617(3) and 116.620)

xxiii Annotation and Evaluation of §116.620 Comments

Submitted 09/20/95 (I) appropriate dates; (II) test methods; (III) instrument readings; (IV) repair results; and (V) corrective actions. Records of flange inspections are not required unless a leak
is detected. (iii) Records for repairs and replacements made due to inspections of H 2 S and SO 2 components shall be maintained. (iv) Records shall be kept for each production, processing, and pipeline tank battery or for each storage tank if not located at a tank battery, on a monthly basis, as follows: (I) Tank battery identification or storage tank identification, if no t located at a tank battery; (II) Compound stored; (III) Monthly throughput in barrels/month; and (IV) Cumulative annual throughput, barrels/year. (v) A plan shall be submitted to show how ongoing compliance will be demonstrated for the efficiency requirements listed in subparagraph (B)(i)(IV) of this paragraph. The demonstration may include, but is not limited to, monitoring flowrates, temperatures, or other operating
parameters. (vi) Records shall be kept on at least a monthly basis of all production facility flow rates (in standard cubic feet per day) and total sulfur content of process vents or flares or gas processing streams. Total sulfur shall be calculated in long tons per day. (vii) Records shall be kept of all ambient property line monitor alarms and shall include the date, time, duration, and cause of alarm, date and time of initial on-site inspection, and date and
time of corrective actions taken. (viii) All required records shall be made available to representatives of the TNRCC, EPA, or local air pollution control agencies upon request and be kept for at least two years. All required records shall be kept at the plant site, unless the plant site is unmanned during business hours. For plant sites ordinarily unmanned during business hours, the record s shall be maintained
at the nearest office in the state having day-today operations control of the plant site. Rev submitted 04/19/1996 (A) appropriate dates; (B) test methods; (C) instrument readings; (D) repair results; and (E) corrective actions. Records of flange inspections are not required unless a leak is detected. (3) Records for repairs and replacements made due to inspections of H 2 S and SO 2 components shall be
maintained. (4) Records shall be kept for each production, processing, and pipeline tank battery or for each storage tank if not located at a tank battery, on a monthly basis, as
follows: (A) Tank battery identification or storage tank identification, if not lo cated at a tank battery; (B) Compound stored; (C) Monthly throughput in barrels/month; and (D) Cumulative annual throughput, barrels/year. (5) A plan shall be submitted to show how ongoing compliance will be demonstrated for the efficiency requirements listed in subparagraph subsection (B b )(I
1 )(IV D ) of this paragraph section. The demonstration may include, but is not limited to, monitoring flowrates, temperatures, or other operating parameters. (6) Records shall be kept on at least a monthly basis of all production facility flow rates (i n standard cubic feet per day) and total sulfur content of process vents or flares or gas processing streams. Total sulfur shall be calculated in long tons per day. (7) Records shall be kept of all ambient property line monitor alarms and shall include the date, time, duration, and cause of alarm, date and time of initial on-site inspection, and date and time of corrective
actions taken. (8) All required records shall be made available to representatives of the TNRCC agency , the EPA, or local air pollution control agencies upon request and be kept for at least two years. All required records shall be kept at the plant site, unless the plant site is unmanned during business hours. For plant sites ordinarily unmanned during business hours, the records shall be
maintained at the nearest o ffice in the state having dayto-day operations control of the plant site. Revision 04/19/96

 Changed section designations when moved to comply
with section numbering.



# III. Proposed Action.

Approval of the adoption of 30 TAC 116.617(3) and subsequent revisions to 30 TAC 116.620 submitted September 20, 1995, April 19, 1996, July 22, 1998, and September 11, 2000. See discussion regarding basis for approval in Sections V and VI of this TSD and in Section III of the Federal Register.